10-K

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.

10

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

11

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

12

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.

13

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.

14

   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.

15

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.

16

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.

17

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

18

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.

19

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.

20

• 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

21

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

22

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.

23

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.

24

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.

25

      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

26

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.

27

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

28

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

29

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.

30

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.

31

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.

32

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.

33

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.

34

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.

35

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.

36

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.

37

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.

38

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.

39

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;

40

(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.

41

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.

42

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

43

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

44

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

45

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-

46

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

47

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.

48

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

49

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.

50

   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)

51

   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

52

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.

53

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.

54

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

55

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

56

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.

57

   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

58

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.

59

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):

60

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.

61

		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

62

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.

63

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.

64

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.

65

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.

66

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.

67

   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

68

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.

69

   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.

70

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).

71

 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):

72

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

73

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.

74

• 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.  

75

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.

76

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.

77

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

78

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):

79

	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-

80

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

81

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.

82

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

104

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):

105

		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.

106

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

107

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

108

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.

109

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

110

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.

111

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)

112

(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

113

		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

114

		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.

115

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.

116

           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;

117

•    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.

118

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.

119

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

120

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.

121

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.

122

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

123

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

124

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

125

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.

126

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.

127

 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

128

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

129

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):

130

	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

131

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

132

			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

133

	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

134

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.

135

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	$	-	$	-

136

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):

137

   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

138

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.

139

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.

140

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.

141

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.

142

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.

143

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.

144

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

145

		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.

146

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

147

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

148

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. 

149

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.

150

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.

151

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

152

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.

153

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.

154

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.

155

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).

162

        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).

163

· 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).

164

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).

166

· 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.

167

(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.

168

· *(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

EX-10.1

Collective Bargaining Agreement

 

NV Energy

6226 W Sahara Ave

Las Vegas, NV 89151-0001

(702) 402-5000

Effective 09/01/2011 – 01/31/2013

IBEW Local 396

3520 Boulder Highway

Las Vegas, NV 89121

(702) 457-3011

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Table of Contents

GENERAL

AGREEMENT...........................................................................................................................................................................................................................................................................................3

ARTICLE NO. 1      Introduction/Continuity of Service/Non-Discrimination...............................................................................................................................................................3

ARTICLE NO. 2     Union Security...................................................................................................................................................................................................................................................5

ARTICLE NO. 3     Exclusive Functions of Management.........................................................................................................................................................................................................6

ARTICLE NO. 4     Union Activity....................................................................................................................................................................................................................................................7

ARTICLE NO. 5     Status of Employees........................................................................................................................................................................................................................................8

ARTICLE NO. 6     Working Hours and Rates of Pay.............................................................................................................................................................................................................15

ARTICLE NO. 7     Seniority and Promotions...........................................................................................................................................................................................................................22

ARTICLE NO. 8     Grievance Procedure....................................................................................................................................................................................................................................25

ARTICLE NO. 9     Safety.................................................................................................................................................................................................................................................................27

ARTICLE NO. 10     Holidays...........................................................................................................................................................................................................................................................29

ARTICLE NO. 11     Vacations........................................................................................................................................................................................................................................................31

ARTICLE NO. 12     Sick Leave/Disability.................................................................................................................................................................................................................................33

ARTICLE NO. 13     Employee Benefit Programs....................................................................................................................................................................................................................38

ARTICLE NO. 14     Leaves of Absence........................................................................................................................................................................................................................................45

ARTICLE NO. 15     General Provisions.....................................................................................................................................................................................................................................48

ARTICLE NO. 16     Working Rules..............................................................................................................................................................................................................................................50

ARTICLE NO. 17     Term of Agreement.....................................................................................................................................................................................................................................53

EXHIBIT III     Check Off Authorization....................................................................................................................................................................................................................................55

EXHIBIT IV    Temporary Layoff Provisions...........................................................................................................................................................................................................................56

CLERICAL

ARTICLE NO. 4     Union Activity..................................................................................................................................................................................................................................................58

ARTICLE NO. 5     Status Designation........................................................................................................................................................................................................................................59

ARTICLE NO. 6     Working Hours and Rates of Pay.............................................................................................................................................................................................................61

Alternative Shift Agreements     Four-Ten Hour Shift Schedule................................................................................................................................................................................67

EXHIBIT I           Job Classificaiton Description.....................................................................................................................................................................................................................69

ARTICLE NO. 4     Union Activity.................................................................................................................................................................................................................................................73

ARTICLE NO. 6     Working Hours and Rates of Pay............................................................................................................................................................................................................75

ARTICLE NO. 16     Working Rules..............................................................................................................................................................................................................................................80

EXHIBIT I           Job Classificaiton Description............................................................................................................................................................................................................81

Alternative Shift Agreements     Four-Ten Hour Shift Schedule..............................................................................................................................................................................102

1

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION

ARTICLE NO. 4     Union Activity..............................................................................................................................................................................................................................................104

ARTICLE NO. 6     Working Hours and Rates of Pay.........................................................................................................................................................................................................105

Alternative Shift Agreements     Twelve-Hour Shift Schedule................................................................................................................................................................................109

Alternative Shift Agreements     Four-Ten Hour Shift Schedule..............................................................................................................................................................................114

Alternative Shift Agreements     Thirty-Six for Forty.................................................................................................................................................................................................116

ARTICLE NO. 16     Working Rules...........................................................................................................................................................................................................................................119

EXHIBIT I           Job Classificaiton Description...................................................................................................................................................................................................................120

LOA                             Charles lenzie/Harry Allen Complex Agreement......................................................................................................................................................................132

LOA                             Electric System Control Center Operators...............................................................................................................................................................................138

2

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

AGREEMENT

This Agreement, made and entered into as of September 1, 2011, by and between NV Energy, a corporation, hereinafter referred to as the Company, and Local Union No. 396 of the International Brotherhood of Electrical Workers, an affiliate of the A.F.L./C.I.O., hereinafter referred to as the Union.

WITNESSETH

Whereas, for the purpose of facilitating the peaceful adjustments of differences that may arise from time to time between the parties hereto, and to promote harmony and efficiency to the end that the Company, the Union and the general public may mutually benefit. Now therefore, in consideration of the provisions, covenants and conditions herein contained, the parties hereto agree as follows, to-wit:

ARTICLE NO. 1

Introduction / Continuity of Service / Non-Discrimination

1.1 INTRODUCTION:  The Company, in Clark and Nye counties, in the state of Nevada, a public utility engaged in the service of generating, transmitting and distributing electric power and energy, hereby recognizes Local Union No. 396 of the International Brotherhood of Electrical Workers, A.F.L./C.I.O., as the exclusive bargaining agent for its employees who are employed in Customer Service, Districts, Material/Warehousing, Reprographic Services, Mail Room/Receiving Departments, Lines, Fleet Services, Meter Services, Communications, Materials, Generation, Substations, and Survey Organizations  excluding all supervisory, confidential and professional employees within the meaning of the National Labor Relations Act, such covered employees more specifically defined in Exhibit I (CLASSIFICATION DESCRIPTIONS), for the purpose of collective bargaining with respect to rates of pay, wages, hours of employment and other conditions of employment which may be subject to collective bargaining.

1.2 CONTINUITY OF SERVICE:  It is mutually recognized that the interest of the Company, the Union and the welfare of the general public, requires the continuous rendering of service by the Company, and the parties agree that recognition of such obligations of continuous service is imposed upon both the Company and its employees.

The Company, to facilitate the continuous performance of such service, agrees to meet with the Business Manager of the Union or his designated representative in reference to any matter within the scope of the Agreement, and agrees that it will cooperate with the Union in its efforts to promote harmony and efficiency among all of the employees of the Company.

The Union agrees that the employees covered by this Agreement, will not be called upon or permitted to cease or abstain from the continuous performance of the duties pertaining to the positions held by them with the Company. The Company agrees to do nothing to provoke interruption of or to prevent such continuity of performance as required in the normal and usual operations of the Company's property. It is mutually agreed that any difference that may arise between the above parties shall be settled in the manner hereinafter provided.

The Union agrees that the employees covered by this Agreement will individually and collectively perform loyal and efficient work and service and that they will cooperate in promoting and advancing the welfare of the Company and the protection of its service to the public at all times.

The Union agrees that there will be no strikes, stoppages of work or slowdowns of the Company's operations during the term of this Agreement, and the Company agrees that there will be no lockouts during the term of this Agreement.

3

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

1.3 NON-DISCRIMINATION:  Neither the Company nor the Union will discriminate against any employee in the application of the terms of this Agreement because of race, religion, sex, age, color, national origin, veteran status, disability or any other legally protected status.  It is understood that job titles used in this Agreement, which indicate the male gender, are not intended to restrict classifications to employees of the female gender.

1.4 LAWS:  It is understood and agreed that if mandatory laws or government rules or regulations applicable to or in conflict with any of the provisions of this Agreement become effective and binding upon the parties, such conflicting provisions of this Agreement shall be subject to modification as required and the parties shall meet and confer to determine mutually agreeable language to conform to the laws, government rules and/or regulations.

If laws, government rules and/or regulations hereafter enacted require changes in the structure and/or services provided by the Company, then the Company and Union will, upon mutual consent, reopen negotiations concerning the terms of this Agreement that are directly affected by the changes.

1.5 AMENDMENT:  This Agreement shall be subject to amendment at any time by mutual consent of the parties. Such amendment must be written, state the effective date of the amendment, and be executed in the same manner as this Agreement.

1.6 PICKET: No employee covered hereunder shall be required, as a condition of employment, to pass through a picket line recognized by the Union provided that said picket line is in connection with a lawful strikesanctioned by a Union which has a legal right to represent the employees of the struck Employer and the strike and picket line in connection with a primary dispute with said struck Employer until a neutral gate is established. However, in the event of an emergency the employee may be required to pass through the picket line.

4

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 2

Union Security

2.1 UNION DUES:  The Company shall deduct money from Union employees' wages and pay it to the proper officers of the Union, provided the employee who is a member of the Union individually and voluntarily authorized such deduction to be made. The form of the check-off authorization is attached to this Agreement as Exhibit III (CHECK OFF AUTHORIZATION).  The Union shall hold the Company free and harmless from any claims or damages from any party whatsoever for making deductions and shall indemnify the Company against any and all claims or damages, which may originate from the dues check-off process.

2.2 NEW EMPLOYEES:  The Company agrees to notify the Union of the name and address of new employees within thirty (30) calendar days of their date of hire. The Union Business Manager and / or a designated representative and the Human Resources (HR) Representative will participate jointly in New Employee Orientation; this will provide an overview of Nevada work law and the goals and responsibilities of both the Union and the Company.

5

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 3

Exclusive Functions of Management

3.1 BUSINESS MANAGEMENT:  The supervision and control of all operations and the direction of all working forces, including the right to hire, to suspend or discharge for proper cause, to transfer employees, to relieve employees from duty because of lack of work and for other legitimate reasons, is vested exclusively with the Company.

3.2 DISCIPLINE: The Company retains the right to exercise discipline in the interest of good service and the proper conduct of its business, provided an employee who has been laid off, discharged, or disciplined shall be advised in writing of the reason or reasons for such action and shall be offered suitable representation, if so desired, at the time such reasons are provided. Furthermore, should the employee or the Union feel that the terms or conditions of this Agreement have been violated; either shall be entitled to grieve such action in accordance with the provisions set forth in Article 8 (GRIEVANCE PROCEDURE) of the Agreement.

6

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 4

Union Activity

4.1 UNION BUSINESS: An employee who requests time off for Union activities, in addition to regular time off, shall be granted such request if such time off will not inconvenience the operations of the Company or increase its operating expenses; provided further, that such employee shall receive no compensation from the Company for such time off.

UNION STEWARD BUSINESS: The Union steward shall, upon request to the supervisor, be allowed reasonable time during regular working hours, without loss of pay, to attend to Union matters on the job, provided such time is not used for solicitation of membership or collection of dues, and does not interfere with regular work schedules.

UNION LEADERSHIP ACCESS: The Company shall allow the Business Manager/Financial Secretary and their designated representatives of the Union access to Company property twenty-four (24) hours a day, seven (7) days a week provided that the Union prearranges access with an e-mail request to HR and a copy to the manager and supervisor of requested area before entering any Company property. Union Leadership will give at least three (3) business days notice and in turn HR will approve the request within two (2) business days so long as such access does not interfere with the operations of the Company. In situations where such timeframes are not feasible, the Company may grant access.

4.2 BULLETIN BOARDS: The Company agrees to permit the Union to use reasonable space for the purpose of posting officially signed Union bulletins upon the bulletin boards and/or electronic mail, which are furnished by the Company.

4.3    CONTRACTING WORK: Refer to Tabs.

7

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 5

Status of Employees

5.1 EMPLOYEE STATUS DESIGNATION: Employees shall be designated as temporary, probationary, or regular.

TEMPORARY: Temporary employees are eligible for 401(k) Plan after completing one year of service and having worked at least 1,000 hours in that year.

Temporary employees are not eligible for Medical, dental, vision, prescription drug program, LTD, Basic Life, Accidental Death Dismemberment (AD&D), Business Travel Accident, Supplemental Life, Pension unless subsequently hired as a regular employee, Dependent Care Flexible Spending Account (DCFSA), Health Care Flexible Spending Account (HCFSA). All benefits for which temporary employees may be eligible are set forth in this article.

TEMPORARY (Applicable only in Clerical): A temporary employee is one who is hired to fill a position for which there is a temporary authorization. Typically, temporary employees are not hired to perform duties normally assigned to regular employees; temporary employees are hired to perform administrative functions to assist regular employees; and are hired for a specific function and set period of time not to exceed 1,040 hours.

If a temporary employee is offered and accepts a regular position, an adjusted date of hire, crediting actual time worked, will be calculated.  If the temporary employee has worked at least 1,040 straight time hours, without cumulative absences of thirty (30) calendar days or more at the time the regular position is awarded, the employee shall be eligible for all applicable benefits on the effective date of the award.

If a temporary employee is offered and accepts a regular position that the employee has not previously occupied while at the Company, the employee must complete a probationary period to evaluate work performance.  If, however, the employee has previously occupied the position being awarded, the employee shall receive credit toward the probationary period for actual time worked in that position.

If a TEMPORARY OR LEASED/AGENCY employee works at least 1,040 straight time hours during a twelve month (12) period in the same temporary position, the position will become authorized.  The selection for the position will be made in accordance with Article 7, Seniority and Promotions.

The Company will endeavor to provide the Union with a list of temporary and leased/agency employees and hours worked.

TEMPORARY (Applicable only in T&D & Generation): (Does not apply to T&D UDC or Mapping classifications) A temporary employee is one who is hired to fill a position for which there is temporary authorization. If a temporary employee is offered and accepts a regular position, an adjusted date of hire, crediting actual time worked, will be calculated. If the temporary employee has worked at least 1,040 straight time hours, without cumulative absences of thirty (30) calendar days or more at the time the regular position is awarded, the employee shall be eligible for all applicable benefits on the effective date of the award.

If a temporary employee is offered and accepts a regular position that the employee has not previously occupied while at the Company, the employee must complete a probationary period to evaluate work performance.  If, however, the employee has previously occupied the position being awarded, the employee shall receive credit toward the probationary period for actual time worked in that position.

8

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

If an employee works at least 1,500 hours during a twelve (12) month period in the same temporary position, the position will become authorized and the employee will be offered regular status in that position.

PROBATIONARY:  A probationary employee is one who is hired to fill an authorized full-time or part-time position. Full-time probationary employees shall be eligible for benefits the first of the month following the date of hire. Part-time probationary employees shall be eligible for benefits in accordance with this agreement.

This language is not intended to conflict with the six (6) month probation period.

During the probationary period, the employee may be terminated at the discretion of the Company as long as the termination is not discriminatory and is not for the purpose of keeping jobs filled with probationary employees. Probationary employees who have not satisfactorily completed a formal departmental training and appraisal program may, at the discretion of supervision, have their probationary period extended by up to three (3) months.  Supervisors shall not extend the probationary period if they do not have a formal training and appraisal program in place or have failed to use those programs.  No later than two (2) weeks prior to the completion of the first six (6) months, the supervisor must notify the employee and the Union Business Manager in writing, if the probationary period will be extended.

In computing the effective date of a change in status from a probationary to regular employee, interruptions in employment, caused by the following circumstances, shall not be credited:

•   Discharge

• Resignation

• Absence for more than an accumulative total of thirty (30) calendar days due to:

•   Lay off

•   Sickness

•   Industrial disability

•   Other causes.

If the employee's combined absences, during the probationary period, are for a period greater than the employee's combined actual work time, the employee shall be terminated.  The transfer of a probationary employee from one job to another without interruption of work time shall not be considered a break in employment.  At the end of the probationary period as defined above, the employee will become a regular employee and will rank in seniority from the original date of hire.

REGULAR: A regular employee is one who has completed a probationary period and is in an authorized full-time or part-time position.

RETURN TO BARGAINING UNIT: A member of the bargaining unit being transferred to a non-represented position due to the lack of Bargaining Unit work shall retain Company seniority for all purposes including layoff, if the employee is returned to the bargaining unit within one (1) year of the initial transfer.

Any employee who bids and accepts a MPAT position within the Company and for any reason returns to the bargaining unit in a full-time regular position shall have an adjusted hire date crediting regular hours worked with the Company for purposes of Company seniority after five (5) years of completed service in a Bargaining Unit position. This language is not intended for any classification that is organized by the Union or granted voluntary recognition by the Company.

9

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

5.2   APPLICATION REFERRAL: The Company recognizes the Union as a valuable source for employment referrals, due to the mutual interest in the profitability of the Company.  As such, when additional employees are needed to do work which comes under this Agreement, the Company will indicate its requirements, relative to knowledge, skills, and abilities, and will give the Union an equal opportunity to refer applicants for employment.  The Company retains the right to evaluate each candidate and make the final hiring decision.

5.3 TEMPORARY LAYOFF PROVISIONS:  In recognition of the competitive nature of the utility business, innovative solutions are required when unforeseen challenges present themselves.  Accordingly, there may be operational circumstances that would permit the temporary layoff of employees for short-term periods of time, out of line of seniority, on a voluntary basis.  These provisions are detailed in Exhibit IV (TEMPORARY LAYOFF PROVISIONS) of this Agreement.

5.4 LAYOFF PROVISIONS:

DEFINITION OF QUALIFIED:  For purposes of defining "qualified", as used in this Article, the definition shall be that an employee is qualified to perform any position, in the CBA, which the employee has previously occupied at the Company.

NOTIFICATION:  If it becomes necessary for the Company to layoff regular employees due to lack of work, the Company shall give affected employees as much notice as possible; but in no event shall employees receive less than twenty-one (21) calendar days notice of layoff.  Where temporary, part-time and probationary employees are involved, no notice of layoff is required.

SENIORITY:  Layoff in all cases due to lack of work will be determined by Company seniority within the classification affected by the layoff.  If two (2) or more employees have the same Company seniority date, the following process will be used for breaking the tie:  Alphabetically by Hired Last Name … if last names are the same, then First Name …if last name and first name are the same, Middle Name; if last name, first name and middle name are the same, month, day of birth, and year will be used.  Employees who are to be laid-off will be permitted to displace a less senior person in any classification for which they are qualified, or may be qualified with minimal training.

RETURN TO BARGAINING UNIT: A member of the bargaining unit being transferred to a non-represented position shall retain Company seniority for all purposes including layoff, if the employee is returned to the bargaining unit within one (1) year of the initial transfer. Employees who leave employment for any reason and return to the bargaining unit within 12 months or less will have their time bridged for seniority, vacation, sick leave, and benefits. There will be no probationary period.

FOUR (4) YEAR QUALIFIER:  Any MPAT employee of the Company who accepts a position in the bargaining unit will establish a new date of seniority for the purpose of future layoffs, except as defined above.  This date will reflect the day in which these employees accept such a position and will be effective for four (4) years. If there is a reduction in classifications in the bargaining unit, these employees will use the above-mentioned date as their seniority date for the purpose of this reduction or layoff.  After four (4) years of service in the bargaining unit, any employee impacted by this language, will be credited with all Company seniority for the purposes of reduction in classification or layoff.

RECALL:  In the event of a recall, the Company shall provide notification to affected employees by certified mail to their address of record.  Such employees must keep the Company informed of the address where they can be reached.  Recalled employees must report to work no later than fourteen (14) calendar days from the date the certified letter was received.  Employees who do not report to work within fourteen (14) days from the date the letter was received will be considered a voluntary resignation of employment.  Employees will only be considered for recall to the classification from which they were laid-off, unless they make a written application within fourteen (14) calendar days from the date of notification of layoff, to human resources, for any

10

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

other position for which they are qualified.  Applications that do not meet this time frame will only be considered after all timely applications have been honored.  Employees must submit a written notice to human resources to rescind their application for consideration for previously held positions prior to formal notification of return to work.  Any employee who refuses a recall to any requested position will be considered voluntary resignation of employment and will waive all recall rights to any other position.  Employees who have displaced a less senior person in any classification shall be given an offer to return to their former jobs if the vacancy is in their former classification.  Recall rights shall cease on any layoff in excess of twelve (12) months.

TEMPORARY RECALL: In the event of a temporary recall, in accordance with Article 4.3 (Contracting Work), an employee may decline such temporary recall without waiving their rights for recall to a regular position, provided the temporary assignment is for less than ninety (90) days. If an employee accepts a temporary assignment, all benefits will be reinstated upon return to work and they will have recall rights for one (1) year from the date of any subsequent layoff. This right does not expire until the employee has returned to work or refused an offer to return to work. Any subsequent layoff will not create a liability for an additional severance benefit in accordance with this Article.

EMPLOYMENT STATUS:  Any regular employee who is laid-off due to lack of work has a right to replace any part-time or temporary employee within (5) working days after notification of layoff, provided the regular employee is qualified to perform the duties of the position filled by the temporary employee.  If a regular employee is laid-off because of lack of work and is subsequently offered and accepts the first recall for employment within one (1) year after layoff, the employee shall resume the status of regular employee and shall be credited with Company seniority previously accrued.  Employees who are recalled in a classification previously held, or for one in which they are qualified, will not be required to serve another probationary period and will be eligible for benefits immediately.  However, employees who leave the service of the Company due to voluntary severancein accordance with this Article, or layoff and who are re-hired after one (1) year from the date of layoff or severance shall not be credited with Company seniority at the time of re-employment and shall be required to serve a new probationary period.  Upon completion of five (5) years of subsequent service, an adjusted date of hire will be calculated crediting actual time worked with the Company.  This date will be used for the purposes of Company seniority and all related benefits.

5.5   SEVERANCE:

Bargaining Unit Severance Pay Plan: Severance Provision is for employees laid off due to lack of work. For the duration of the severance benefit period, employees will receive medical/dental/vision benefits based on whatever plan they were enrolled in at the time of layoff provided that they make any required premium contributions.

# Of weeks for each full year of continuous service (Max. 17 years) + Minimum # of weeks of severance One (1) = Maximum # of weeks of severance Eighteen (18)

Enhanced Severance & Retirement Bridge Program: Employees are eligible for the “enhanced severance & retirement bridge program” options specified below if they are determined to be no longer required due to displacement as a result of sale, divestiture, merger, bankruptcy or any other business event as defined by the Company. Affected employees who are covered under the traditional retirement plan component of the Retirement Plan and have 85 points (age plus years of benefit accrual service) at the time of their displacement will be eligible for severance pay, if they choose to retire in lieu of exercising their “bumping rights”.  The 85 point provision does not apply to affected employees covered under the cash balance plan component of the Retirement Plan.

Notification Of Individuals: Company will notify Union and employees affected by the event as soon as possible.

11

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Placement: The Company and the Union will work to place affected employees in available positions for which they are qualified.

Volunteers will be requested and selected by Company seniority. If there are no volunteers, reverse seniority will be used to select employees for the enhanced severance and retirement bridge program.

Employees may be offered a comparable position, defined as the same headquarters location and wage (i.e. comparable or higher wage if qualified).

•   The Employee will have 5 (five) working days to notify the Company of their decision. If the employee accepts the comparable position, it will be awarded to them at the appropriate wage rate.

•   If the Employee refuses the comparable position, the Employee will be terminated with no severance.

Employees may be offered a non-comparable position (defined as requiring relocation of greater than a 35 mile radius and/or a wage reduction):

•   If the Employee accepts and is awarded the non-comparable position, he/she will be eligible for re-training, if required, and up to $2000 relocation expense.

•   If the Employee declines, he/she will be eligible for the Enhanced Severance Option or Retirement Bridge Option described below.

Enhanced Severance Option:

•   Two (2) weeks of base pay for each year of service, with a maximum of 52 weeks.

•   A lump sum payment of $4,500 for training or outplacement services

•   Six (6) months of Company paid COBRA

OR

Retirement Bridge Option (applicable only to Traditional Retirement Plan Component):

For affected employees covered under the traditional retirement plan component of the Retirement Plan, if an affected employee who achieved eighty (80) points (in combination of age and benefit accrual service at the time they are displaced, the affected employee will not have to reach the minimum age 55 requirement to be eligible to retire upon the displacement under the traditional retirement plan component or for post retirement medical benefits for which the affected employee is eligible. The affected employee’s retirement benefit under the traditional retirement plan component will be reduced by 5% per year for each year under age 62.

Example:

An affected employee who is covered under the traditional retirement

plan component of the Retirement Plan and is age 49 with 31 years of benefit

accrual service (for a total of 80 points) at the time he/she are displaced would be

eligible to “retire” and receive post retirement medical benefits for which they are eligible.

Alternatively, an affected employee who is covered under the traditional retirement plan component of the Retirement Plan may add the following schedule of points to either their age or years of service, or a combination thereof, to affect their retirement eligibility. The employee must achieve a minimum age of 55 (including points) with at least ten (10) years of service to be eligible to retire under the traditional retirement plan component and receive post retirement medical benefits.

12

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Years of Service                    Points

                                                                          0-9                                        0

                                                                        10-14                                      3

                                                                        15-19                                      4

                                                                          20+                                       5

Example:

An employee who is age 52 with 28 years of vesting service at the time they are

affected can add 3 points to their age and effectively become age 55, and 2 points

to their years of service, which gives them 85 points. This qualifies them for an

unreduced full retirement benefit under the traditional retirement plan component

at the time they retire.

The Retirement Bridge Option is not applicable to employees covered under the cash balance plan component of the Retirement Plan.  Eligible employees can select only one option – either Severance or Retirement Bridge. Employees who are eligible to retire without using the Retirement Bridge Program (and employees covered under the cash balance plan component) are still eligible for severance pay. If an employee declines both the Enhanced Severance and Retirement Bridge Program options, they will be eligible for consideration under Article 5.4 “bumping rights”.

The severance calculation will apply with one (1) week per year with a minimum of one (1) week severance, i.e. a one-year employee would receive two (2) weeks of severance pay. Rehire rights will be limited to one (1) year.  The Company will provide a list of affected employees and listings of job openings as they occur. The Union will be responsible for monitoring the program. When an employee exercises Article 5.4 “bumping rights”, the affected employee (bumped employee) will start at the “placement” step of the enhanced severance and retirement bridge program.

See EXHIBIT A     ARTICLE No. 5.5 Severance Flow Chart

For purposes of the Flow Chart, the Retirement Bridge Option is shown but is only relevant if applicable. The Retirement Bridge Option is only applicable to individuals covered under the traditional retirement plan component of the Retirement Plan, and is not applicable to individuals covered under the cash balance plan component of the Retirement Plan.

13

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

EXHIBIT A

ARTICLE NO.  5.5

  Severance Flow Chart

14

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 6

Working Hours and Rates of Pay

ALTERNATIVE SHIFTS:

It is understood that with a thirty (30) calendar days notice the Company or the Union may notify each other and discontinue use of alternative shifts.

RED CIRCLE/GRANDFATHER:

All current Red Circle wages, as of the ratification of the 2005 CBA, shall be “Grandfathered” at such wage and shall continue to receive yearly wage increases; however the wage schedule for “Grandfathered” employees will not be included in the CBA.  All “Grandfathered” employees shall be identified at their current wage and a list shall be shared with the Union & Company.  Going forward, Red Circled employees shall be defined as employees frozen at their current rate and shall not receive pay increases until annual increases catch up.  In the event an employee is involuntarily forced to a lower classification, other than as a result of discipline, such employee shall be “Grandfathered” and shall continue to receive annual wage increases for as long as they remain in their “Grandfathered” position.

6.2   BREAK PERIODS (Applicable only in Clerical): A fifteen (15) minute relief period shall be provided for all employees not working seven day coverage during each one-half (1/2) of the shift.  Work conditions permitting, each break period shall be given as near the middle of each one-half (1/2) of the shift as possible.  If an employee is required to work four (4) continuous hours of overtime, then a fifteen (15) minute break shall be provided, halfway between the four (4) hour period.

BREAK PERIODS (Applicable only in T&D and Generation): A fifteen (15) minute relief period shall be provided for all employees not working seven day coverage during each one-half (1/2) of the shift.  Work conditions permitting, each break period shall be given as near the middle of each one-half (1/2) of the shift as possible.

6.3 LUNCH PERIODS (Applicable only in Clerical): With the exception of part-time employees, supervisors will establish a meal period, without pay, of either one-half (1/2) or one (1) hour.

LUNCH PERIODS (Applicable only in T&D & Generation):  Supervisors will establish a meal period without pay, approximately four (4) hours after the start of a shift, but no later than six (6) hours after the start of the shift.  Employees who are required by management to begin their lunch more than one (1) hour before or after the regular start of lunchtime shall be paid during the lunch period at the straight time rate.  There are two (2) pay possibilities for employees with an unpaid lunch.  For this example the employees shift is from 7:00 am to 3:30 pm with a one-half (1/2) hour lunch from 11:30 am to noon.

Example #1

Earlier or Late Lunch

Employees who are required to take their lunch either one (1) or more hours before or one (1)

or more hours after their regular established lunch period, shall have one-half (1/2) hour of

straight time pay added to the hours they worked for that day.

Example #2

No Lunch

Employees who take no lunch period shall have their allotted lunch period added to the end of their work day at time and one half (1 ½).

REGULAR DAY-SHIFT AND SHIFT EMPLOYEES:  The unpaid lunch period shall not exceed one-half (1/2) hour unless mutually agreed to by the Company and the Union.

15

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

SEVEN DAY COVERAGE EMPLOYEES:  These employees will be considered to have a paid lunch period as part of their regular shift.

Example

A line troubleman whose shift is from 7:00 am to 3:00 pm will have a thirty (30) minute paid

lunch period to be taken in accordance with operational efficiencies.

6.4 OVERTIME: Refer to Tabs.

6.5 OVERTIME EQUALIZATION (Does not apply to UDC or Mapping Classifications): The Company will endeavor to distribute overtime work as evenly as possible among those employees qualified to perform such work. For the purpose of distributing overtime, the Company will maintain and post overtime lists in each sub-department indicating time offered and time worked. Each department will create policies and procedures (BY LOCATION, SHIFT – as defined by Article 6.1 AND CLASSIFICATION REFER TO TABS), for overtime equalization through labor/management meetings.

6.6 PAY PROVISIONS:

PAY DAYS:  Pay days shall be at biweekly intervals.

WAGES: The schedule of job classifications and wage rates, as mutually agreed to, are made a part of this Agreement, and are marked "Exhibits I and II" respectively.

Wages shall be paid at biweekly intervals on the Thursday following the close of the two-week pay period provided that if the regular payday falls on a holiday, payment shall be made on the preceding workday.

SPECIAL PAY REQUESTS:The Company recognizes there will be circumstances such as weeks of vacation and vacation in association with holidays, which will create special requests of the payroll department.  Unless the situation is an emergency, all special checks will be limited to individuals who are absent for at least the Wednesday through Friday of a pay week.  Exceptions to this practice will require written approval from the department manager and must be presented to payroll no later than forty-eight (48) hours in advance of the requested time for payment.

RECOVERING OVERPAYMENTS: Deductions from an employee's wages, to recover overpayments made in error, will not be made unless the employee is notified prior to the end of the month following the month in which the check in question was delivered to the employee.  The Company and the employee will agree upon a schedule for re-payment.

6.7 CALL-OUTS: Call out is defined as when an employee who is neither working regular time or overtime hours, is directed or asked to report by an authorized representative to work for hours which had not been previously assigned.  In all call out situations, an employee will receive double time for the hours worked as a result of the call out.

Employees called out for overtime duty shall receive at least two (2) hours pay at the appropriate rate.

The employee(s) authorized to assign call out work will be as defined by departmental policy.

6.8   REST TIME: Employees who are required to work overtime within the eight (8), ten (10), twelve (12) hour period immediately preceding their scheduled starting time, according to the employees assigned shift, shall be entitled to time off with straight time pay equal to time worked during this time frame.  This is not applicable to a call out or scheduled overtime of three (3) hours or less immediately preceding the employee's normal starting time.

16

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

If an employee is entitled to rest time off, such time off would normally begin at the start of the regular shift.  By mutual Agreement between the supervisor and the employee, rest time may be taken during the last part of the regular shift. An employee shall not be required to work during his rest period provided adequate relief is available, however, should an employee be required to work during this period, he shall receive straight time for all time worked during his rest period in addition to his rest period pay.

6.10 SHIFT DIFFERENTIAL: Fixed shift employees will be paid their shift differential for all hours worked on that day.  For example, a second shift employee who works ten (10) hours on a particular day would be paid ten (10) hours of second shift differential.

FIRST SHIFT:  No shift differential shall be paid for the first shift.

SECOND SHIFT: A differential shall be paid for the second shift according to the following schedule:

September 1, 2011 through January 31, 2013 ....................$1.45 per hour

THIRD SHIFT:  A differential shall be paid for the third shift according to the following schedule:

September 1, 2011 through January 31, 2013 ………………$1.60 per hour

The appropriate overtime rate will be applied to the shift differential.  Shift differentials shall be payable only for hours actually worked and shall not be payable for non-work time such as holidays, sick leave, vacation and rest time.

SEVEN-DAY COVERAGE EMPLOYEES (Applicable only in T&D): Employees will be paid the shift differential applicable to the shift under which any hours worked may fall.

6.11 ESTABLISHING PERMANENT SCHEDULES (Applicable only in T&D and Generation): The right to establish working schedules and methods of shift rotation for employees, to assign individuals to schedules and to make changes in schedules, rests with the Company.  Whenever the Company assigns an employee to a schedule that is different than the schedule they are regularly assigned and such assignment is expected to last ninety (90) calendar days or more, the following conditions shall apply:

NOTIFICATION (Applicable only in T&D and Generation): Employees will be given as much notice as possible and in all cases, at least twenty-four (24) hours and prior to the end of their last regular shift.  In this notification, the employee will be informed of the hours of work, including the days off and meal periods if applicable, work location, expected duration of the shift if other than indefinite, estimated composition of the work force, and the type of the shift (regular day, fixed shift, or rotating).  The Company will limit days off to days inclusive of or in conjunction with Saturday or Sunday providing that such schedules will not interfere with the continuous rendering of service by the Company. If the Company fails to satisfy the twenty-four (24) hour notification requirement, the premium for the first five (5) days of the new shift will be extended until the notification requirement has been satisfied.

STAFFING OF SCHEDULES:

VOLUNTEERS (Applicable only in T&D and Generation): When new shifts are announced, the Company will permit affected employees to volunteer for these assignments.  The highest Company seniority will be used to select from the volunteers and these employees will not receive a premium for their first five (5) days of this new assignment.

LEAST SENIOR QUALIFIED (Applicable only in T&D and Generation): The least senior, qualified employee in the classification affected, may be assigned.  Any employee so assigned

17

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

will receive a premium of time and one-half (1 1/2) for the first five (5) days of this assignment for all hours worked outside of their previous schedule.

RIGHT OF ASSIGNMENT (Applicable only in T&D and Generation): The Company may assign employees to these schedules for operational efficiency purposes.  Any employee so assigned will receive a premium of time and one-half (1 1/2) for the first five (5) days of this assignment for all hours worked outside of their previous schedule.

SHIFT DIFFERENTIAL (Applicable only in T&D and Generation): The appropriate shift differential, if any, shall apply immediately to all hours worked for those who volunteer for these shifts. For those employees paid a premium for the first five (5) days of such an assignment, the shift differential will apply beginning on the sixth day of the assignment, or the first day on which the premium is not paid.

RETURN TO ORIGINAL OR OTHER SCHEDULE (Applicable only in T&D and Generation): Employees, who are assigned to a new schedule and are returned to their original schedule before five (5) days have elapsed, will be entitled to the premium mentioned above for the five (5) day period.  Employees assigned to a second, new schedule during the initial five (5) day premium payment period will receive an additional five (5) days of premium from the date the new schedule begins.

Example #1

Employees who receive four (4) hours of premium per day who are returned to their former shift after only two (2) days would continue to receive this premium for three (3) additional workdays.

Example #2

Employees who have worked only two (2) days of a new schedule and are notified they will start a second new schedule on the fourth day, will receive eight (8) days of premium pay (three (3) for the first schedule and five (5) for the second).

Example #3 (Applicable only in Generation)

Employees who are assigned a new schedule during their regular work schedule are entitled to premium pay as outlined in Article 6 for the next forty (40) regular straight time hours.

TRAINING EXCEPTIONS: The Company may, for the purposes of training only, change schedules without incurring the premium penalties mentioned above.  The Company will notify all employees as far in advance as possible, but not later than the end of their last scheduled work day in the week prior to such training.  This notification will detail the nature, location, and duration of the training.  If such notification is not given, and an employee is called at home and informed of a change in schedule for training purposes, this employee will be paid time and one-half (1 1/2) for the first two (2) days of the training for all hours worked outside of their normal schedule.

TRAVEL TIME FOR OUT OF TOWN TRAINING:  Any employee who is required to travel out of town on a normal day off or after normal working hours for the purpose of Company training, will be paid actual driving time to and from the training site.  When flying to such training, employees will be paid one (1) hour from their home to the airport, actual flying time to the destination, and one (1) hour from the airport to the hotel.  All compensation for such travel time will be at a straight time rate and will not be considered time worked.

SCHEDULE PREFERENCE AGREEMENTS (Applicable only in T&D and Generation):  The Company recognizes that in departments where multiple schedules exist, there may be a desire to create a mechanism for movement between such schedules, while protecting the operational efficiencies of the organization.  To satisfy these mutual interests, departments are encouraged to create shift preference Agreements, which will define the terms and conditions for the transfer from one schedule to another.  Under no circumstances, would such transfers create

18

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

premium pay liability in accordance with the provisions of this Article.  Each schedule preference Agreement will be created through labor/management meetings within the affected work group and will be acknowledged by memorandum of Agreement between the Company and the Union.

6.12 ASSIGNMENT TO AN ESTABLISHED SCHEDULE (Applicable only in T&D and Generation):  When seven (7) day coverage employees, other than relief employees, are transferred from one schedule of work days or work hours to another established and populated schedule, they shall not be entitled to overtime compensation for work performed during regular work hours of any day involved in the transfer, provided that:

• They have been notified of such transfer not less than twenty-four (24) hours in advance of the starting time of the new shift or work period;

• They have had a minimum of one shift off between schedules;

• As a result of such transfer they have not been required to work more than forty (40) hours at the straight time rate in any workweek involved;

• They have not been required to work more than one (1) short change in the work week involved, provided, however, that such short change was not the result of a voluntary action on the part of an employee, (i.e., Calling in sick, taking an unauthorized day off for personal reasons, etc.).

6.13 EMERGENCY OR TEMPORARY SCHEDULES (Applicable only in T&D and Generation): The Company may schedule employees to work for periods other than their regular work hours when additional schedules are required for emergency or temporary conditions.  Such conditions are expected to last for less than ninety (90) calendar days and, if they exceed this time frame they will be considered to be established schedules requiring compliance with the procedures for staffing and establishing schedules defined above, unless mutual Agreement to extend such schedules is established by the Company and Union.

NOTIFICATION (Applicable only in T&D and Generation): The Company shall communicate the hours of work, meal periods, days off, location, nature of the work, estimated composition of the workforce, and expected duration of this schedule.

STAFFING OF EMERGENCY OR TEMPORARY SCHEDULES:

VOLUNTEERS (Applicable only in T&D and Generation): The Company may solicit volunteers for assignment to these schedules.  If employees volunteer for these assignments, they will receive a premium of time and one-half (1 1/2) for all straight time hours worked outside of their normal schedule or shift for the first five (5) days of this assignment.  When there are more volunteers than required for the shift, the most senior, qualified employees will be assigned.

LEAST SENIOR QUALIFIED (Applicable only in T&D and Generation): The least senior, qualified employee in the classification affected, may be assigned. Any employee so assigned will receive a premium of time and one-half (1 1/2) for the first five (5) days of this assignment for all hours worked outside of their previous schedule.

RIGHT OF ASSIGNMENT (Applicable only in T&D and Generation): The Company may assign employees to these shifts for operational efficiency purposes. Any employee so assigned will receive a premium of time and one-half (1 1/2) for the first five (5) days of this assignment for all hours worked outside of their previous schedule.

SHIFT DIFFERENTIAL (Applicable only in T&D and Generation): After the five (5) day premium requirement has been fulfilled, the appropriate shift differential shall apply.

19

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

RATE OF PAY AND ROTATION (Applicable only in T&D and Generation): On the first day that there is no requirement for a premium and each day thereafter, the appropriate rate of pay and shift differential, if applicable, will be provided for all hours worked.  If any such schedule extends beyond forty-five (45) calendar days, the Company and the Union may agree to rotate the assigned employees.  Employees returned to their former schedule as a result of this rotation, will not be entitled to the premium mentioned above.

RETURN TO ORIGINAL SCHEDULE (Applicable only in T&D and Generation): At the completion of this assignment, employees will be returned to their original schedule without a requirement for any additional premium payment. Employees, who are assigned to an emergency or temporary schedule and are returned to their original schedule before five (5) days have elapsed, will be entitled to the premium mentioned above for the five (5) day period.

Example (Applicable only in Generation):

Employees who are assigned a new schedule during their regular work schedule are entitled to premium pay as outlines in Article 6 for the next forty (40) regular straight time hours.

6.14 OUT OF TOWN WORK:

BOARD AND LODGING (Applicable only in T&D and Generation): The Company will furnish adequate board and lodging for all employees sent out of the service territory (for the purpose of this article Laughlin is considered out of the service territory). This rule does not apply to lunch meals where employees start from and return to headquarters every day, nor does it apply to employees hired for any particular job, which may be outside the city, or where employees travel to and from regularly assigned headquarters on Company time.

EQUALIZING ASSIGNMENTS (Applicable only in T&D and Generation): When making temporary out of town assignments, the Company will endeavor to distribute such assignments equally among all employees qualified to perform such work.

MILEAGE ALLOWANCE (Applicable only in T&D and Generation): Except as provided herein, employees electing to travel to and from their assigned work locations shall do so at their own expense. When an employee is authorized to drive his own car to conduct Company business, he will receive a mileage allowance equal to Internal Revenue Services (IRS) maximum allowable mileage expense. Requests for the allowance described herein shall be submitted to, and distributed by the Company every two (2) weeks and in accordance with procedures established by the Company.

6.15 MEALS:

MEAL TIMES:  When working overtime before or after the regular day, or shift, or when called out for overtime work, and such work is continuous for two (2) hours or more, the Company shall provide all meals unless employees are released before the meal time. The normal unpaid meal times shall be:

§   one and one-half (1-1/2) hours before the employee's normal starting time,

§   eight (8) hours before the employee's normal starting time,

§   four (4) hours after the normal starting time, and

§   two (2) hours after the normal quitting time

Meals will be provided as close to these times as circumstances of the work will permit.  Employees may elect to complete their assignment and take their meal period upon completion of their task. This meal period would be unpaid time unless directed by supervision to work through the meal period and such work continues more than one (1) hour from the stated mealtime.  This paid meal period will be limited to one-half (1/2) hour at the appropriate rate of pay.

20

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

CALL OUT (Applicable only in T&D and Generation): When an employee is called out one and one-half (1 1/2) hours or more previous to his starting time, the Company shall provide breakfast and reasonable time to eat.

Applicable only in Clerical: For purposes of this Article, no meal allowances will be provided for any scheduled overtime work on an employee’s usual days off when the Company has given advance notice more than twelve (12) hours prior to the start of scheduled overtime and prior to the end of the last shift.

MEAL RATES:  When employees are released on or after a normal meal period, or periods as outlined above, and do not elect to eat a Company provided meal, they shall be given a meal allowance. These allowances will be paid through the payroll system in the employee's next paycheck.

September 1, 2011 through January 31, 2013……………..$16.00

If an employee elects to consume a Company provided meal in lieu of the allowance, the cost of any meal shall not exceed the allowance as provided for above.  If the cost of the meal exceeds this amount, the employee will be notified of the amount of the difference and the employee must reimburse the amount within thirty (30) calendar days after receipt of such notification.  The department’s Vice-President may waive these limitations if such limitations place an undue hardship on the employee.

6.17 EARLY RELEASE:  Employees relieved from duty, for reasons other than misconduct, during the first half of the regular day or regular shift shall be paid for not less than one-half (1/2) of the   shift; if relieved after having been on duty more than one-half (1/2) of the regular day, they shall be paid for a full shift, except that if they are relieved at their own request they shall be paid only for time worked.  These provisions do not apply to overtime assignments.

21

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 7

Seniority and Promotions

7.1 SENIORITY: There shall be one (1) type of seniority, namely, Company seniority.  Company seniority shall be considered in such matters as retirement, layoff, and whenever provisions of this Agreement refer to seniority.  In cases, where two (2) or more employees have the same Company seniority date, the following process will be used for breaking the tie:  Alphabetically by hired last name … if last names are the same, then first name … if last name and first name are the same, middle name; if last name, first name and middle name are the same, month, date of birth, and year will be used.

7.2 SENIORITY POSTINGS: The Company shall post a Company seniority list on the Company Intranet (Matrix) to be updated annually. Any seniority corrections should be made in writing to HR. Upon request, the HR office will furnish the Union Leadership or his designee a copy of the current seniority list.

7.3 STAFFING VACANCIES:

POSTING REQUIREMENT:  When there are no qualified employees who have requested an intra-departmental work location change into job vacancies, which are expected to last for more than ninety (90) calendar days, the Company shall post such job vacancies or new jobs on the Company Intranet, or at www.NVEnergy.com, and on reader boards* throughout the company facilities for a period of fourteen (14) calendar days. It shall be the duty of the Company to include the nature of the job, its location and duties, reasonable qualifications required and the rate of pay, unless such information is listed in the CBA. Positions posted will be available for Union review on the Company Intranet, or at www.NVEnergy.com. Employees may file their applications via the Company Intranet or at www.NVEnergy.com.However, the Company may not consider any application received after the job bid closing date. The successful candidate will be transferred to their new department no later than thirty (30) calendar days after the award of the job. If the successful candidate is not transferred to their new department after thirty (30) calendar days, the employee will begin receiving the new pay wage on the thirty-first (31) day after the date of the award.

*Subject to IT&T technology and feasibility.

JOB POSTING SYSTEM: The Company shall publish job posting and awarding procedures, which, at a minimum, comply with the provisions of this Agreement. These procedures will constitute the Company's job posting system.  Any bargaining unit employee covered by the CBA may apply and compete equally for any position within the Company. Employees are disqualified from bidding if they have a letter of discipline, which is less than one (1) year old in their HR personnel file.  Employees will not be disqualified from bidding if they have a letter of discipline for meter reading accuracy, which is less than one (1) year old in their HR personnel file, provided that the job for which they are bidding does not involve reading meters as part of their regular duties. Employees will not be disqualified from bidding if they have a letter of discipline which is less than one (1) year old in their HR personnel file for cash handling provided that the job for which they are bidding does not involve cash handling as part of the regular duties. Any employee who is hired or voluntary returns to their former position in accordance with article 7.8 (Trial Period) to any position within the CBA shall not be considered for another position for six (6) months from their hire date or date of return. However, if there are no internal applicants for a position, the Company and Union agree to consider the aforementioned employees.

In addition, any employee who is hired, promoted, or transferred to a Meter Reader position shall not be permitted to apply for another position for six (6) months from their hire date or date of promotion/transfer.

22

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

SELECTION CRITERIA:  Exclusive of the provisions of Articles 7.9 (INTRA-DEPARTMENTAL WORK LOCATION CHANGE), in filling vacancies the following factors shall be considered:

§   Trade Knowledge

§   Training

§   Past performance with the Company

§   Ability, skill, adaptability, efficiency

§   In addition, the Company retains the right to administer equally fair tests, demonstrations, or physical assessments when such tests will assist materially in determining the qualifications of employees.

When, in the discretion of the Company, all factors are substantially equal, Company seniority shall govern.

INTERVIEW:  If an interview is scheduled, then the Company will contact the Union Business Manager or Assistant Business Manager at least three (3) days prior to any scheduled interviews. The Union Business Manager or designated representative will observe as a neutral.

HEARING PROCEDURES:  In lieu of any grievance procedure concerning Article 7.3 (STAFFING VACANCIES), the Company shall offer the three (3) most senior bidders (if applicable) and the employee with the second highest matrix score (if applicable) who are more senior than the successful bidder a hearing before the bid committee with the steward for the department, the senior person or persons and one (1) other Union member.  If the number of senior bidders exceeds the parameters mentioned above, a group meeting will be conducted with the remaining senior bidders to explain the decision and answer any relevant questions.  The Company shall not assume any penalty for bid hearings that are delayed.

NO QUALIFIED BIDDERS:  If no applications are received from any qualified bargaining unit employees within the posting period, before filling the position from outside of the bargaining unit, the Company shall follow the provisions described in the Transfer Policy.

7.5   MOVING EXPENSES:  Should the Company assign an employee, who has not

volunteered, for reassignment, to an established Company headquarters located more than thirty (30) driving miles by the most reasonable route from his regularly established Company headquarters, and such assignment is not temporary in nature, the Company will pay the employee $2000 for moving expenses, for the purpose of establishing a new primary residence, within a two (2) month period immediately following such assignment.  In addition, the Company shall pay the actual costs to relocate a mobile home, which is the employee's primary residence.

7.6   SUBDEPARTMENTS: Refer to Tabs

7.7 PAY PROVISIONS: When employees are awarded bids in accordance with Article 7.3 (STAFFING VACANCIES) of this Agreement, their rate of pay for the awarded job shall be the rate established for the classification as listed in the appropriate Agreement.  If the awarded job has more than one rate, such rates being based on time spent in classification, the employees shall be assigned the lowest rate in the classification, which will provide an increase to the employee. Employees thus assigned a rate step above the starting rate will not advance to a higher step until they have served the time indicated by the assigned step. Should no rate in the classification provide an increase, the employee shall be assigned the highest rate of the new classification as defined in the CBA.

7.8 TRIAL PERIOD:  Employees promoted or transferred in accordance with this Article shall be employed on the job to which they were promoted or transferred for a reasonable trial period not to exceed ninety (90) calendar days.  If, following the trial period, they are still unable to

23

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

perform the job to which they are promoted or transferred, they shall be returned to the former job classification they held or to another job classification of similar requirements and the previous rate of pay, as determined by the Company.

Example:

An FSR is awarded an FSI position. Before forty-five (45) calendar days, he decides that he no longer wants to be an FSI. He is then returned to an FSR position (or similar position) at his previous rate of pay.

7.9   INTRA-DEPARTMENTAL WORK LOCATION CHANGE: Employees desiring to change work location within the same sub-department and classification shall submit a work location change form to the appropriate department head. Through labor/management meetings, departments shall develop procedures for work locations changes.

(Applicable only in Generation): The transfer will be awarded to the most senior eligible employee within the classification. Successful candidates will agree to a six (6) month trial period with associated goals and measures, mutually agreed upon by the Company and the Union. At three (3) months the Company shall present the transferred employee with an evaluation of his/her progress thus far. The Company will be responsible for providing any and all assistance available to the employee in order for them to become proficient in this time period. If at the end of the evaluation period the transferred employee is unable to perform the work, the employee will be returned to the location and classification from which they transferred. The next senior qualified employee requesting a transfer will be given the same opportunity. Employees hired after February 1, 2002 will follow article 7.3 Selection Criteria and Article 7.8 prior to being granted an intradepartmental transfer. The most qualified individuals will be offered the opportunity first; when all factors are substantially equal seniority will prevail. Successful candidates will agree to a ninety (90) day trial period with associated goals and measures.

7.10 BRIDGED TIME FOR RE-HIRED EMPLOYEES: Previous employees, who are rehired as a regular employee, one year after the date they left the Company (as regular employees), shall not be credited with Company seniority at the time of re-employment and shall be required to serve a new probationary period.

When the employee has completed five (5) years of subsequent service, in a full-time regular position, an adjusted hire date will be calculated, crediting regular hours worked with the Company for purposes of Company seniority and all related benefits other than retirement benefits in which case the Plan document control.

This agreement is separate and not intended to conflict with Article 5.4 of the CBA.

24

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 8

Grievance Procedure

8.1   DEFINITION:  A grievance shall be defined as a dispute regarding the interpretation and application of the provisions of this Agreement filed by the Union or by an employee covered by this Agreement alleging a violation of the terms and provisions of this Agreement.  Disputes specifically excluded in other Articles of this Agreement from the Grievance Procedure shall not be construed as grievances within the definition set forth above.

8.2   TIME LIMITATIONS:  The Company and the Union recognize the grievance process as an effective tool in resolving differences in the work place. Once timely notification of a grievance has been given, the Union and Company may mutually agree to extend the time limitations set forth below in writing.  However, it is in the interest of both the Company and the Union to expedite the process and encourage the timely resolution of the issue.  Except for the time period for the Union to file a grievance, if the Union fails to adhere to the other time periods set forth below, the Company may provide the Union with notice of such failure and provide the Union 3 working days to cure any such failure.  If the failure is not cured by the expiration of the 3 working day notice period, a procedural forfeit of the grievance will occur.  If the Company fails to adhere to the time periods set forth below, the Union may provide the Company with notice of such failure and provide the Company 3 working days to cure any such failure.  If the failure is not cured by the expiration of the 3 working days notice period, a procedural forfeit of the grievance will occur and the Union would be awarded the remedy requested as long as such request was, (i) reasonable,  (ii) consistent with the violated article or articles, and (iii) applicable only to the actual Grievant or Grievants. Any procedural forfeits will be considered non precedent setting and shall not be considered in the arbitration or the consideration of any other grievance.

The Union and Company, by mutual Agreement, may elect to bypass certain steps, due to the nature of the grievance.

Except by mutual agreement to extend the time limitations set forth in this Article in writing, or as otherwise provided herein, an arbitrator shall not have the authority to excuse a failure by the Union, the Company or the aggrieved employee to comply with the time limitations set forth, regardless of the reason given for such failure.

8.3   GRIEVANCE PROCESS:

NOTIFICATION:  When a dispute arises relative to the administration of the provisions of this Agreement, the employee and/or Union Steward must complete a grievance form citing the article or articles allegedly violated by the Company and submit it to the appropriate supervisor for signature (with an electronic copy to the Labor Manager) no later than twenty-one (21) calendar days after the grievance arises.  The time period to file a grievance shall start from the first day the Company can show that the Union or an employee affected by the Company’s action knew or should have known of the situation.

It is in the best interest of both parties to keep the same Steward involved from start to finish.  The Company will make a reasonable effort to use the same Steward throughout the process.

After each step in the process, the Union shall officially sign the grievance form, verifying that their interests have been satisfied or to pursue resolution at the next step.

STEP ONE (GRIEVANCE MEETING – SUPERVISOR):  The highest level supervisor or their designee over that workgroup shall schedule a meeting with the grievant and steward within twenty-one (21) calendar days of receipt of the grievance form.  Absent unusual circumstances, such meeting should be held within 30 days of receipt of the grievance form.  The grievant and the supervisor will define interests and work on resolving the issue in a manner satisfying those interests.  If the issue is not resolved at Step One (1), the Supervisor will refer the grievance to

25

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

the next Step, accompanied by any and all pertinent documentation gathered during the initial investigation, with the reason or reasons for denying the grievance within twenty-one (21) calendar days of the Step One (1) meeting.

STEP TWO (GRIEVANCE MEETING—LABOR MANAGER):  Within twenty-one (21) calendar days after receipt of the Step 1 answer, or in the case of a termination, twenty-one (21) calendar days after notification of the termination decision, if the Union and/or the employee want to pursue the grievance, the Union must notify the Labor Manager of the decision to pursue the grievance and give the grievance to the Labor Manager.  The notification must be sent via electronic mail.  The Labor Manager or their designee shall schedule a meeting with the grievant, steward, supervisor, HR Partner and the Business Manager or their designees within twenty-one (21) calendar days of receipt of the grievance form from the Union.  The Company and Union shall review all information provided and conduct further investigation if necessary. If the grievance is not settled at the Step Two (2) meeting, the Company will communicate its position in writing within twenty-one (21) calendar days of the Step Two (2) meeting.  This written notification will be sent via electronic mail.

The parties may mutually agree that they may resolve a dispute at any step in the process; however, resolution at Step 2 or below is non-precedent setting and without prejudice to the position of either party, unless mutually agreed to otherwise.

STEP THREE (ARBITRATION):  Within twenty-one (21) calendar days of receipt of management’s Step 2 response, the Union may request arbitration by delivering a written notice (sent via electronic mail) to the Labor Manager of its intent to arbitrate the dispute.  If the Union does not respond within twenty-one (21) calendar days of receipt of the Step 2 response, the issues involved in the grievance will be considered resolved and the matter closed.

Within fourteen (14) calendar days after receipt of the notice of intent to arbitrate, the parties will request the Federal Mediation and Conciliation Service to furnish a list of seven (7) arbitrators primarily from the southwest region of the United States from which the arbitrator shall be selected.  Such selection shall be accomplished by the Union and the Company striking one (1) name from the list in turn until only one (1) name remains.  Each party has the right to strike one complete list.  The parties may also mutually agree to use this same selection process from an agreed upon panel of arbitrators instead of using the Federal Mediation and Conciliation Service.

TERMINATIONS

In recognition of the significance of terminations, arbitration relative to termination grievances shall be expedited whenever possible.  In this regard, termination grievances must proceed directly to Step Two (2) of this procedure.  However, if either the Company or the Union fails to process the grievance in a timely manner, the Arbitrator shall have the authority to excuse such failure if the Arbitrator finds the failure has a reasonable basis and did not result in a disadvantage or prejudice to the other party.  Unless mutually agreed to extend the time limitations in writing, termination grievances should be arbitrated within six (6) months of the termination date.

SCOPE OF ARBITRATION

The arbitrator’s decision shall be submitted in writing and shall be final and binding on all parties to this Agreement.  The cost of the arbitrator and the cost of necessary expenses required for paying for facilities and recording of the hearing of cases shall be borne equally by the Company and the Union.  The arbitrator shall not have the authority to modify, amend, alter, add to, or subtract from any provision of this Agreement.

26

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 9

Safety

9.1 MUTUAL INTERESTS: The Company and the Union share a mutual interest in fostering safe working conditions for all employees.  The Company and the Union will endeavor to create programs, procedures and policies which will define the Company and the Union as leaders in providing and promoting a safe workplace.  The Company shall make reasonable provisions for the safety of employees in the performance of their work.  The Union shall cooperate in promoting the realization of the responsibility of the individual employee with regard to the prevention of accidents.

9.2 SAFETY COMMITTEE: Each department shall have their own Safety Sub-committee, and at least one (1) representative from each departmental Safety Sub-committee shall serve on the Company's Safety Committee.  The selection of the Company's Safety Committee members shall be made jointly by the Chairman of the Committee and the Business Manager of the Union.  The Chairman of this Committee shall be selected by the Company. Each year thirty three and one third percent (33-1/3%) of the Committee members shall be replaced in accordance with the selection provision.

9.3 REPORTING DEFICIENCIES: Each member of the Safety Committee shall be expected to actively participate in identifying and reporting to the area safety representative any deficiency or unsafe condition discovered in the assigned work area. Recommendations to improve the operational safety shall be made to the manager, safety services, and to the department supervisor. A copy shall also be presented to the Chairman at the next Safety Committee meeting.

9.4 SAFETY MEETINGS: The Chairman shall hold Safety meetings at reasonable intervals subject to call.

9.5 SEMI-ANNUAL INSPECTIONS: Every six (6) months the Safety Committee Chairman shall appoint at least three (3) members to perform an inspection of the Company facilities.  If required, these inspections may occur more often at particular facilities. The Committee Chairman may request additional employees who work at the site to assist in the inspection. The Company will allow the appointees reasonable time, as determined by the Chairman, to perform this inspection. They will prepare a written report, including recommendations for corrective actions and forward it to the Committee Chairman and Company President.

9.6 RULE VIOLATIONS: In the event employees violate safety rules published by the Company, the Company reserves the right to administer appropriate disciplinary action.

9.7 SAFETY INVESTIGATIONS: When a lost time disabling injury occurs as a result of a suspected careless act or unsafe working condition, a safety investigating committee shall be chaired by Safety Services to review the facts and reconcile safety deficiencies and recommend corrective action.  A safety committee member designated by the Union and assigned to the work area in which the injury occurred, shall serve on the investigating committee.

9.8   INCLEMENT WEATHER:  Employees who report for work on a straight-time work day and who, because of inclement weather or other similar cause, are unable to work in the field that day, shall receive pay for the full day.  However, they may be held pending emergency calls and may be given first-aid, safety or other instruction, or they may be required to perform miscellaneous work in the yard, warehouse, or other sheltered locations.  Through labor/management meetings, and in conjunction with safety services, each department shall establish policies, which clarify safe work procedures during inclement weather. Employees on

27

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

overtime days excluding emergencies shall receive pay for time worked or time held on Company property or two (2) hours, whichever is greater.

9.9 RAIN GEAR: Employees who are required to work in the field will be assigned appropriate rain gear, which will be maintained by the employees and replaced by the Company when such gear is worn out in the course of employment and returned to the Company by the employee.

9.10 ENERGIZED PANELS:  Employees who are assigned to work in the field will not be required to work on exposed and energized metering panels during rainy weather but may be assigned related duties as necessary.

9.11 HEALTH AND SAFETY: The parties hereto agree to cooperate in using all reasonable means to eliminate conditions of danger to either the general public, the Company or its employees. No employee shall knowingly engage in an unsafe act. Whenever it becomes necessary to employ day shift employees assigned to the Company's business offices, where security personnel are assigned, outside the normal work hours, and such work is during the hours of darkness, all arrivals and departures from Company owned parking facilities shall be observed and controlled by security personnel. Parking facilities shall, when possible, be adjacent to the Company's business offices.

The Company agrees to furnish such safety devices and equipment including but not limited to first aid kits, AED, CPR protection mask, hard hats, all PPE, safety glasses, leather gloves, sun block, as may be reasonable and necessary for the health and safety of its employees and the Union agrees, on behalf of the employees, that such equipment will be used.

-  -

28

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 10

Holidays

10.1 ELIGIBLE EMPLOYEES: Regular employees and probationary employees, who are eligible for benefits, shall be entitled to holidays off with pay. Employees on leaves of absence or disability leave are not entitled to holiday pay, except if the employee begins leave or returns from leave during the week of a holiday.

10.2 WORKED HOLIDAYS: Shift employees may be permitted to take holidays off which fall on their scheduled workdays. Employees scheduled to work on a holiday shall be paid at the rate of time and one-half (1 1/2) for time worked during regular working hours in addition to holiday pay. Employees who are called out to work on a holiday shall be paid at the rate of double time for time worked in addition to holiday pay. Time worked in excess of the regular workday will be paid at the appropriate overtime premium. Except for shift employees, holidays shall not be considered scheduled workdays.

10.3 COMPANY HOLIDAYS: When a holiday falls on a Saturday, the preceding Friday shall be observed, and when a holiday falls on a Sunday the following Monday shall be observed. Whenever an employee's regular days off are other than Saturday and Sunday, the first day off within the workweek shall be considered as Saturday and the second day off within the workweek shall be considered as Sunday for the purpose of this Article. A rotating shift employee working on a schedule which provides four (4) consecutive days off shall observe the day prior to the four (4) days if the holiday falls on the first of the four (4) days, and shall observe the day following the four (4) days if the holiday falls on any of the other three (3) days for the purpose of this Article.

Holidays	2011	2012	2013
New Years Day	Dec 31	Jan 2	Jan 1
Martin L King Day	Jan 17	Jan 16	Jan 214
Presidents Day	Feb 21	Feb 20	Feb 18
Memorial Day	May 30	May 28	May 27
Independence Day	July 4	July 4	July 4
Labor Day	Sept 5	Sept 3	Sept 2
Veterans Day	Nov 11	Nov 12	Nov 11
Thanksgiving Day	Nov 24	Nov 22	Nov 21
Thanksgiving Friday	Nov 25	Nov 23	Nov 22
Christmas Eve	Dec 23	Dec 24	Dec 24
Christmas	Dec 26	Dec 25	Dec 25
	One (1) floating holiday	One (1) floating holiday		One (1) floating holiday

In addition to the designated Company holidays, eligible employees shall observe one (1) floating holiday in accordance with the provisions of Article 10.4.  It is understood that the one (1) floating holiday does not apply to the Generation 12 hour shift or 36 for 40 shift agreements.

10.4 FLOATING HOLIDAY: An employee may observe a floating holiday on any day the employee desires so long as a seven-day notice has been given regardless of operational or other needs. For the purpose of this article, the calendar week begins Sunday and ends Saturday. Should an employee be called in or be required to work on a previously approved “holiday”, the employee shall be paid the applicable overtime rate, except if both the employee and supervisor mutually agree to change the observance of the holiday. The floating holiday does not carry over from one payroll year to the next, and must be used in the payroll year in which it is received.

29

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

10.5 BANKED HOLIDAYS (Applicable only in T&D and Generation): If eligible employees are required to work on any day observed as a holiday and are authorized to work for the straight time hourly rate of pay, then an equal number of hours will be allocated to their banked holiday account.  With written consent of the Company, employees may carry over up to sixteen (16) hours of banked holidays to the next year.

10.6 TEMPORARY EMPLOYEES: Temporary employees will not receive pay for holidays not worked but shall be paid the appropriate overtime premium for all time worked on holidays.

10.7 SICK LEAVE IN CONJUNCTION WITH A HOLIDAY: An employee who does not report for work either the day before and/or the day after a paid holiday, including the floating holiday, and who has not been excused by his or her supervisor for either the day before and/or the day after a paid holiday shall receive no pay for the holiday. The Company may require satisfactory evidence of an employee's illness or injury before holiday pay will be granted.  If the Company requires medical evidence, the Company must inform the employee of the requirement to provide evidence no later than two (2) hours after the employee's regular starting time on the day of the absence.  If required and the employee does not comply with this request, the employee will not be paid for the holiday or the day of absence, and may be subject to disciplinary action.

10.8 ALTERNATIVE SCHEDULES:  As a result of the implementation of alternative work schedules, any issues associated with the provisions of Article 10 (Holidays) will be resolved by Memorandum of Understanding between the Company and the Union.

30

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 11

Vacations

11.1 CONSIDERATIONS:  Vacation with pay may be granted at any time during the calendar year in which it is earned, subject to the following considerations.

• Desirability of scheduling in such a manner as will cause a minimum of interference with service to the Company's customers, and;

• The selection of all vacation periods based on the employee's Company seniority, provided the selection is made no later than January 31st.

11.2 FIRST TWO (2) CALENDAR YEARS OF EMPLOYMENT: Probationary and regular employees shall earn vacation during the first two (2) calendar years of their employment according to the month in which they are hired.  Probationary and regular employees may request and be granted vacation anytime during this period.

Month HiredVacation Hours

January80 hours

February77 hours

March73 hours

April70 hours

May67 hours

June63 hours

July60 hours

August57 hours

September53 hours

October50 hours

November47 hours

December43 hours

Example:

If an employee is hired March 2008, the employee is granted 73 hours vacation to be used by payroll year-end. New employees may carry their 73 hours vacation over in this scenario. In the beginning of the payroll calendar year of the second year of employment, 80 hours of vacation will be front loaded to be used by payroll year-end.

11.3 ACCRUED VACATION: Regular employees will be granted vacations, with straight time pay, according to the following schedule:

After Continuous Service of                                                                                                  Vacation Hours

2 years through 5 years 80 hours

6 years through 12 years 120 hours

13 years through 20 years 160 hours

21 years through 30 years 200 hours

31 years and above 240 hours

11.4 VACATION ADJUSTMENTS:  An employee's vacation accrual shall be adjusted for all periods of leave of absence including leaves for illness or injury as defined elsewhere in this Agreement by reducing the number of vacation hours accrued in direct proportion to the number of hours of leave within the employee's anniversary year.  Such reductions shall be applied to any accrued and unused vacation available in the calendar year the adjustment is made, or when such adjustment exceeds the employee's available vacation, the excess shall be applied against the employee's next vacation accrual or the employee's final paycheck, whichever occurs first.  It is

31

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

 understood that no adjustment to vacation accrual will be made for sick leave or during the first sixty (60) calendar days of any disability leave.

11.5 VACATION BONUS:  In addition to the vacation accrued in accordance with the above schedule, (ARTICLE 11.3 ACCRUED VACATION) any employee who completes ten (10) years continuous service and each five (5) years of continuous service thereafter, shall be granted a vacation bonus of forty (40) hours in the year such term of employment is attained.  The vacation bonus will accrue, and may be taken subject to the provisions of this Article. Vacation bonuses will be determined based on the employee’s rehire date and not the original hire date which is used to determine the years of service the employee would receive based on Article (7.10 Bridged Time for Re-Hired Employees).

11.6 UNUSED VACATION:  All unused or carried over vacation time accumulated in the year of termination of employment after an employee's first anniversary date, up to and including the employee's last day worked, shall be paid at termination of employment, at the employee's current base rate.  This does not apply to the vacation bonus when the employee has not completed the minimum service specified.

Example:

An employee terminates employment in June, the employee will only receive vacation pay for

six months of that year; i.e. the employees’ vacation allotment is 120 hours a year at time of

termination he will be eligible for 60 hours of pay provided he hasn’t used any vacation.

It is understood that employees may not carry vacation time over to the following year without the written consent of the Company. This does not apply to Article 11.2 (Vacation First Two (2) Calendar Years of Employment).

A regular employee who has been laid off for lack of work and is recalled within one (1) year, who has in excess of one (1) year Company seniority, shall accrue vacation in accordance with Article 11.4 (VACATION ADJUSTMENTS).

11.7 DEPARTMENTAL POLICIES:  Each department will develop standards and procedures for scheduling vacations, which, at a minimum comply with Article 11.1 (CONSIDERATIONS).

11.8 HOLIDAY WHILE ON VACATION:  If a holiday occurs on a workday during an employee's vacation, it shall not be counted as hours of vacation.  The employee shall receive straight time pay for the holiday.

11.9 HOSPITALIZED WHILE ON VACATION:  Employees on vacation, who becomes hospitalized for at least one day, shall not be required to use vacation time during the period of incapacitation.  Employees who are capable of completing any light duty must choose to remain on vacation or report for light duty.

11.10 CALL-OUT WHILE ON VACATION:  An employee shall not be expected to work on his regularly scheduled days off immediately preceding or following pre-scheduled vacation.  However, if an employee is called out and accepts such an assignment on the regularly scheduled days off immediately preceding or following pre-scheduled vacation, the employee shall receive the appropriate overtime rate for this work.  An employee called out during scheduled vacation will be paid double time for all hours worked and the employee may reschedule the unused portion of his vacation hours in accordance with Article 11.1 CONSIDERATIONS above, if the call-out was for work during the employee's normal work hours.  Additionally, if the call-out creates rest time, the employee may reschedule vacation equal to the rest time earned from this assignment.

32

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 12

Sick Leave / Disability

INTRODUCTION

The Union agrees to share the responsibility in protecting the sick leave plan from abuse by any of its members, recognizing that the plan is intended to provide pay coverage under situations of actual need.

MEDICAL ATTENTION

Sick leave may be used for obtaining medical information or treatment including exams or treatments for care of the eyes or teeth of eligible employees. Such absences should be approved in advance where possible and limited to the time necessary for treatment, examination or recovery.

12.1 ELIGIBILITY: Full-time employees shall be entitled to accumulate sick leave with pay at the rate of eight (8) hours of sick leave for each month worked.

12.2 NOTIFICATION AND VALIDATION:  The Company may require satisfactory evidence of an employee's illness or disability before sick leave will be granted. If an employee abuses the sick leave provisions of this Agreement by misrepresentation or falsification, the employee shall restore to the Company all sick leave payments received as a result of such abuse.  An employee must notify their supervisor or a member of management, or see that their supervisor is notified, as soon as it is apparent that the employee will be unable to report for work.  The employee must provide this notification before the beginning of the normal workday.  The employee should notify the supervisor as far in advance as possible of the expected date of return.  Lack of notification without a reasonable explanation will result in denial of sick pay benefits.

12.3 EXCLUSIONS AND EXCEPTIONS.  Employees shall not be entitled to sick leave while on vacations (except as provided in Article 11.9 HOSPITALIZED WHILE ON VACATION), while temporarily laid off by the Company, during the period of notice of severance of employment, upon severance of employment, or while receiving disability payments or industrial compensation.

12.4 SICK LEAVE BONUS: Employees who are eligible for sick leave in accordance with Article 12.1 (ELIGIBILITY), who use no more than two hundred twenty (220) hours of sick leave each five (5) years, shall be granted a bonus of five (5) days vacation in addition to that granted under the provisions of Article 11.3 (ACCRUED VACATION), each five (5) years based on the following considerations:

■   On January 1, 1987, and January 1, of each fifth year thereafter, the sick leave records of those employees with hire dates prior to August 1, 1981, will be audited. Those employees who have used no more than two hundred twenty (220) hours of sick leave during the five (5) year period immediately preceding the audit will be granted five (5) days vacation to be taken within the twelve (12) month period immediately following the audit date and in accordance with the provisions of Article 11 (VACATIONS).

■   For employees hired after July 31, 1981, their sick leave records will be audited as of the first day following the completion of five (5) years and six (6) months of service and each fifth (5th) year following the initial audit. Those employees who have used no more than two hundred twenty (220) hours of sick leave during the five (5) year period immediately preceding the audit will be granted five (5) days vacation to be taken within the next twelve (12) month period immediately following the audit in accordance with Article 11 (VACATIONS).

33

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

■   All unused vacation accumulated under the provisions of this sick leave bonus plan shall be paid at termination of employment as provided under Article 11.6 (UNUSED VACATION) except that no proration of vacation entitlements will be allowed for time periods of less than five (5) years.

12.5 LIGHT DUTY:  Injured employees who are temporarily unable to perform the functions of their own jobs but are capable of performing light duty work shall be released for light duty assignments either within their own department or another area of the Company where work is available.  In the interest of effective case management, the HR department shall administer the light duty work program.  Employees working in light duty assignments shall be eligible for a percentage of their base pay according to the following schedule:

■   100% of base pay for the first ninety (90) calendar days

■   85% of base pay thereafter

■   The employee must have a light duty work release from a doctor. The employee may be allowed to work overtime if it is a continuation of their shift. Employees on light duty will not be eligible for callouts or scheduled overtime. Any employee who returns to work for regular duty must have a full duty release from a doctor. Employees will be eligible for a full light duty benefit after they have worked thirty (30) calendar days from the time of that release. If an employee returned to regular duty status works for less than thirty (30) calendar days and is then returned to light duty status for the same injury or illness, the employee will then continue with the original time period.

Employees, who are injured on the job and are unable to perform their regular duties indefinitely due to partial disability, may be subject to the provisions outlined in Article 12.7 (JOB INCURRED INJURY/PARTIALLY DISABLED EMPLOYEES).

12.6   JOB INCURRED INJURY/SALARY PROTECTION: Any employee who suffers a job incurred injury during the term of this Agreement and who is awarded temporary total compensation benefits as defined in the Nevada Industrial Insurance Act shall receive supplemental disability payments in such amounts and under such conditions as described below:

■   The combined amount of disability compensation to which the employee is entitled under any federal, state, and local law, and from the Company shall not exceed the percent of the employee's weekly earnings, from the table listed below, where such earnings are computed at the employee's regular rate for a forty (40) hour, seven (7) day period.

■   Supplemental payments shall be made for the first day recognized by the Workers’ Compensation Administration, and shall terminate with the date of the last day of disability recognized by the Workers’ Compensation Administration, as evidenced by the remittance portion of the disability check from the Workers’ Compensation Administration, which must be presented to the Company, for a maximum period of benefits as defined in the following schedule of benefits, for any one accident regardless of the various periods of disability which may be compensated for the one accident.

LENGTH OF SERVICE	MAXIMUM PERIOD OF BENEFITS	PERCENT OF BASE EARNINGS
6 months	13 weeks	55
5 years	26 weeks	60
10 years	52 weeks	65
15 years	60 weeks	70
20 years	65 weeks	75

■   For a job-incurred disability of less than five (5) days, which does not qualify for Workers’ Compensation Administration compensation, employees must use any accrued sick leave, and upon exhaustion of such accrued sick leave shall receive disability benefits as defined above. Any medical absence of five (5) days or more due to a work related injury or illness will be paid by the Workers’ Compensation Benefit; employees will not use accrued sick leave.

34

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

■   No supplemental disability payments shall be made for any disabling accident caused by the injured employee's violation of any safety rule.

■   Any employee who performs activities for which compensation is received or which exceed the scope of the prescribed physical limitation pertaining to such disability while receiving disability compensation described in this section, shall forfeit his entitlement to all disability benefits and his employment shall be terminated.

12.7 JOB INCURRED INJURY/PARTIALLY DISABLED EMPLOYEES: When, in the opinion of the Company's doctor after consultation with the employees' doctor, regular employees with at least one (1) year of Company service cannot perform their regular work because of partial disability, but can perform other work, the following plan shall be applicable:

Each case shall be considered on its merits by a committee consisting of the Business Manager of the Union and a HR Representative, and two (2) additional members, one (1) of whom shall be designated by the Union and the other by the Company. The committee shall have the authority to waive the seniority and bidding provisions of this Agreement in order to place the disabled employee, and it shall determine the seniority rights of such employee. This committee may call on anyone who may be able to furnish pertinent information.

In no event will this Article apply if the employee's disability occurs while self-employed or working for others, for remuneration (except on Union business), or is involved in misconduct or an extreme violation of Company safety rules.

The panel shall complete an evaluation of the type of work the employee is able to perform or may be able to perform in the future. Evaluation of the employee's capabilities may include but shall not be limited to a physical examination and doctor’s reports, the employee's physical and mental ability, willingness to work, and trainability.

Depending upon the evaluation of the employee and where necessary and practical, the Company shall provide job related education and training. The panel shall also conduct periodic review of these cases to determine if an employee's condition has changed; if the employee's condition has changed, the panel will reevaluate the employee's job assignment.

The panel will determine the job classification which is appropriate for the work the employee is able to perform, as well as the proper pay rate, taking into account the new classification pay rate or the rate indicated on the following schedule, whichever is greater.

Years Of Company Service	A Pay Rate That Is Not Less Than
1 to 4 years inclusive	70% base rate when injured
5 to 14 years inclusive	80% base rate when injured
15 to 24 years inclusive	85% base rate when injured
25 years and over	90% base rate when injured

As long as such employee is paid more than the maximum rate for the job classification in which the employee is placed, the employee shall receive only fifty (50) percent of any base wage increase or lump sum payment in lieu of a base wage increase. Such fifty (50) percent shall be calculated on the employee's personal rate at the time of the increase.

The placing of a disabled employee in a different job shall not constitute an increase in the Company's normal work force. However, the Company may temporarily increase the number of

35

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

authorized positions to accommodate an individual when a future vacancy is clearly defined and recognizable.

If the committee is unable to place an individual in accordance with these provisions they would be eligible for vocational rehabilitation training, and benefits through the Workers Compensation Insurance. Upon this determination, the individual's employment with the Company will be terminated, and any accrued benefits will be paid at the time of termination.

The parties agree that the provisions of this Article may be suspended with sixty (60) days written notice, documenting the reasons for this request and the interests, which would need to be addressed for the continuance of this program.

INJURIES RELATIVE TO DOG BITES

The Company and Union discussed meter reading injuries relative to dog bites. The Company and Union agreed to communicate and reinforce, with a representative from the Call Center and Commercial Offices, the importance of their initial contact with the customer in annotating relevant information regarding animals. The Company will endeavor to locate and provide a list of local attorneys who might be interested in representing employees negatively impacted by dog bites.

12.8 SHORT TERM DISABILITY BENEFIT: A full-time employee, who has worked more than one thousand forty (1040) straight time hours who shall suffer any disabling illness or injury while not in work status, shall be entitled to disability payments in such amounts and under such conditions as described herein:

■   An eligible employee shall be entitled to receive payments not to exceed the percent of the employee's weekly straight time earnings, such earnings to be computed on the employee's regular rate for a forty (40) hour, seven (7) day period, for a maximum period of benefits at the percent of earnings as defined in the following schedule of benefits.

LENGTH OF SERVICE	MAXIMUM PERIOD OF BENEFITS	PERCENT OF BASE EARNINGS
6 months*	13 weeks	55
5 years	26 weeks	60
10 years	52 weeks	65
15 years	60 weeks	70
20 years	65 weeks	75

* Employees in this category may be granted up to thirteen (13) additional weeks of leave without pay for continued disability.

■   No disability payments for an illness shall be made until at least a three (3) business days waiting period has been observed, however, an employee must use accrued sick leave to satisfy the waiting period or to extend the waiting period to the maximum of the amount of accrued sick leave.

■   Any female employee who becomes pregnant and is unable to work shall be entitled to disability benefits under this Article, as described above, subject to the following conditions. She must present a document from her attending physician saying that she is under the doctor's care because of the pregnancy and is unable to work. The period of the disability shall begin at least three (3) days after the attending physician declares the employee disabled and shall end when the employee is no longer disabled as determined by the attending physician. Pregnant employees must use all accumulated sick leave before disability payments will start. A female employee will not be eligible for pregnancy related disability benefits except for her own disability. An employee who is on maternity

36

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

leave and recovering from disability may request to have her leave extended for up to three (3) months after termination of pregnancy for child care or other reasons.

■   Any employee who performs activities for which compensation is received or which exceed the scope of the prescribed physical limitation pertaining to such disability while receiving disability compensation described in this section, shall forfeit their entitlement to all disability benefits and their employment shall be terminated.

■   Any employee who returns to work in a light-duty status from short-term disability will not create a new benefit eligibility until they have had a full-duty release and worked for thirty (30) calendar days from the time of that release. If an employee returns to short-term disability without satisfying this requirement, their short-term disability benefit will reflect their prior usage and continue until expiration of such benefits.

■   Any employee, who is unable to perform the duties of their position as a result of a non-job-incurred injury, would be considered for any vacancy for which they are qualified. If awarded a position in accordance with Article 7 (SENIORITY AND PROMOTIONS), the employee would receive the appropriate rate of pay for that position.

■   Any employee that exhausts their short-term disability benefit and is unable to return to work at that time, may request one unpaid leave of absence for up to ninety (90) calendar days to allow time for further recuperation or possible vacancies for which they are qualified. Such employees will be allowed to continue their medical coverage at the appropriate COBRA rate for this period of time. If this individual is unable to return to work at the expiration of this unpaid leave, their employment with the Company will be terminated and all accrued benefits will be paid at the time of termination.

12.10 FAMILY SICK LEAVE (FSL): Employees will be allowed to use up to thirty-two (32) hours, in four (4) hour increments, of accrued sick leave per payroll year to care for an immediate family illness or emergency. Unused hours cannot be carried over to the next year. There will be no occurrences when sick leave is used for this purpose. FSL cannot be used in conjunction with a Holiday or Vacation.  However, if an employee is on an approved leave under the Family and Medical Leave (“FLMA”) for the care of another, such employee will be permitted to exceed 32 hours of FSL use, and will be required to use any available accrued sick leave while on FMLA leave.

37

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 13

Employee Benefit Programs

This Article is amended and restated as of September 1, 2011, except as otherwise set forth herein.

13.1   MEDICAL/PRESCRIPTION DRUG/DENTAL/VISION

The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan (“Welfare Plan”) shall be incorporated, by reference, into the Agreement for purposes of establishing the terms and conditions governing benefits for Medical, Prescription Drug, Dental, Vision, Disability, Group Life Insurance, Flexible Spending Accounts, and Wellness Benefits.

The Company agrees to maintain all of these benefits for eligible employees during the term of this Agreement and will provide corresponding medical expense, vision expense, and dental expense coverage for eligible dependents in accordance with the terms and conditions of the Welfare Plan document for the life of this Agreement.  The Company reserves the right to select any insurance carrier or to self-insure all or any portion of these benefits.

OPTIONS:  The Company will permit employees to select between health care plan options which may be available under the plan.  Currently, such options are:

1. Fully-insured PPO (Administered and governed by the respective insurance carrier)

2. Health Maintenance Organization (HMO) (Administered and governed by the respective insurance carrier)

3. No coverage, contingent upon proof of other insurance.

OPEN ENROLLMENT:  Initial open enrollment due to a change in plan options will be in November 2011.  Subsequently, elections of medical plan options will be made in the fall of each year during an open enrollment period.  The election remains in effect for the entire Plan Year, unless the employee incurs a “Qualifying Status Change” as defined by the Internal Revenue Code Section 125, Cafeteria Plan, and makes a consistent benefit election change as permitted under the Welfare Plan.  With the exception of the Flexible Spending Accounts, if an employee fails to enroll, coverage will default to the previous year’s coverage for himself and dependents, provided such coverage is available.

EMPLOYEE CONTRIBUTIONS:  The rates for medical coverage, will be actuarially determined each plan year, based on previous claims experience.  The rates for the fully insured PPO and the HMO will be as quoted by the respective insurance carriers.  Payroll deductions for required employee contributions will be taken the first and second pay periods of each month, and will be made on a pre-tax basis to the extent permitted under law.

During the term of this Agreement, the cost share for all options will be 82% Company and 18% Employee.

COVERAGE OUTSIDE THE PPO AREA:  The Sierra Select PPO service area includes Nevada, Washington County, Utah and Mojave County, Arizona. Members use the Sierra Health provider network when receiving care within the service area. Members have access to the United Healthcare Choice Plus provider network if they travel or live outside the Sierra Select PPO service area.

DENTAL BENEFIT:  The Company will, during the term of this Agreement, provide a dental care benefit, including a dental PPO and an orthodontic benefit for all eligible employees and dependents in accordance with the terms and conditions of the Welfare Plan document.  Coverage includes the following:

38

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

■   Annual benefit is $2,000 per person

■   Annual deductible is $25 per person/$75 family

■   Preventive care is covered at 100% with no deductible if a PPO provider is used and 100% after $25 deductible if a Non-PPO provider is used.

■   After deductible, the following dental treatments are covered at:

■   80% for Basic Periodontics/Prosthetics and Oral Surgery

■   50% after deductible for Major Restoration

■   Orthodontia is covered at 100% after deductible up to a separatelifetime maximum of $2,000

■   All percentages are subject to usual, customary, and reasonable(UCR) charges

VISION BENEFIT:  A vision care benefit will be available for eligible employees and eligible dependents during the term of this Agreement under the terms and conditions of the Welfare Plan document.  This benefit covers professional services; examinations every twelve (12) months based on the last date of service; lenses every twelve (12) months based on the last date of service, frames once every twenty-four (24) months based on the last date of service.  Examinations will have a twenty-five ($25) dollar co-pay for a PPO provider and a maximum of forty dollars ($40) paid for a non-PPO provider.  The vision care benefit also provides for up to two pair of prescription safety glasses for employees whose job duties require eye protection in accordance with the Company’s established safety standards, once every twelve (12) months based on the last date of service, if needed.

PRESCRIPTION DRUG BENEFIT:  A prescription drug benefit will be available for eligible employees and eligible dependents during the term of this Agreement under the terms and conditions of the Welfare Plan document.  This benefit will allow participants to obtain prescription drugs through preferred pharmaceutical outlets.  The following co-pays currently apply for this benefit:

♦         Retail

1.           Generic (“Tier 1”) = $5 co-pay for 30-day supply

2.           Brand Name (“Tier 2”) = $15 co-pay for 30-day supply

3.           Non-Preferred (“Tier 3”) = $35 co-pay for 30-day supply

♦         Mail Order - Available for “Maintenance” (Life-Sustaining) Drugs Only

1.           Generic (“Tier 1”) = $10 co-pay for 90-day supply

2.           Brand Name (“Tier 2”) = $30 co-pay for 90-day supply

3.           Non-Preferred (“Tier 3”) = $70 co-pay for 90-day supply

If there is no generic substitute, the brand name co-pay applies.  If the doctor indicates (“dispense as written”) and a generic substitute is available the brand name co-pay applies.  If the employee and/or dependent choose a brand name and there is a generic available, they will pay the brand name co-pay plus the difference in cost between the generic and brand name prescription.

13.2   WELLNESS PROGRAM

Full-time employees and part-time employees (provided they work at least 20 hours per week) will be eligible for the Company’s wellness program during the term of this Agreement in accordance with the terms and conditions of the Welfare Plan document.  Participation in the wellness program may begin on the 1st day of the month following date of hire.  Temporary employees are not eligible to participate.

39

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

The following terms will apply:

●   Employee participation shall be voluntary.

●   The Company will pay the entire cost of the wellness program.

●   The level of benefits, terms and conditions are at the discretion of the Company.

13.3   DEPENDENT CARE FLEXIBLE SPENDING ACCOUNT (DCFSA)

The Company will, during the term of this Agreement, provide a Dependent Care Flexible Spending Account (DCFSA) that allows pre-tax funding of dependent care and child care expenses, in accordance with the terms and conditions of the Welfare Plan document.  Eligibility will begin on the first day of the month following date of hire.  Temporary employees are not eligible for this benefit.  Payroll deductions will be taken the first and second pay periods of each month.

13.4   HEALTH CARE FLEXIBLE SPENDING ACCOUNT (HCFSA)

The Company will, during the term of this Agreement, offer a Health Care Flexible Spending Account (HCFSA) that allows pre-tax funding of qualified health care expenses for employees and dependents, in accordance with the terms and conditions of the Welfare Plan document.  Eligibility will begin on the first day of the month following date of hire.  Temporary employees are not eligible for this benefit.  Payroll deductions will be taken the first and second pay periods of each month.

13.5   RETIREMENT

The NV Energy Retirement Plan, restated on January 1, 2000, is a defined benefit pension plan bearing Plan No. 001 (“Retirement Plan”).  The Plan, as amended, shall be incorporated by reference into this Agreement.  The Company has, since January 1, 1976, funded all benefits under the Retirement Plan.  All participants in the retirement plan, which was in effect before January 1, 1976, have and are guaranteed all accrued benefits under that retirement plan as computed on December 31, 1975.  Following is a summary of certain Retirement Plan provisions, which will be in effect during the term of this Agreement, provided that eligibility, coverage, benefits and all provisions of the Retirement Plan shall be governed by the terms and conditions of the Retirement Plan document.

A.         CASH BALANCE PLAN

Effective December 31, 2008, a cash balance plan component will be implemented under the Retirement Plan.  The accrued benefits of all current participants (other than participants who satisfy the “75 Point” requirement described below and who elect to continue in the traditional retirement plan component) will be converted to an account under the cash balance plan component to be maintained for the participant.  All eligible employees who are hired or rehired, or who transfer to a union position, on or after January 1, 2009, will be covered under (and, if applicable, converted to) the cash balance plan component.

The conversion from the traditional retirement plan component to the cash balance plan component will be calculated by the actuary for the Retirement Plan based on legal requirements and reasonable actuarial factors.  In connection with the conversion, actuarial adjustments based on the “Rule of 85” under the traditional retirement plan component will be applied to the traditional retirement plan component accrued benefit as of December 31, 2008, only for participants who satisfy the “Rule of 85” age plus benefit accrual service requirements.  Thus, for participants who have not satisfied the “Rule of 85” requirements at the time of the cash balance conversion, the actuarial increase, if any, resulting from the application of the “Rule of 85” will be effective at the time of retirement, assuming the “Rule of 85” requirements are met at the time.  Additionally, although the interest factor used in the conversion calculations will not include any “wear away” assumptions, benefits will be subject to “wearing

40

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

away” in the future, based on a number of factors, including interest rates and time of retirement.

Benefits under the cash balance plan component will be funded entirely by the Company.  A participant’s cash balance account will be credited with contribution credits and interest credits.  Beginning January 2009, contribution credits will be made monthly (the first contribution credit to be made in February 2009).  For active participants on October 13, 2008, the contribution credit rate will be equal to a specified percentage of the participant’s eligible earnings as follows:

                                                                    Total Age + Service                                                                Percentage of Eligible

                                                                                    at December 31, 2008                                                                           Earnings                      

                                                                          Under 55                                                                                              4%

                                                                             55-59                                                                                                  5%

                                                                             60-64                                                                                                  6%

                                                                             65-69                                                                                                  7%

                                                                       70 or above                                                                                              8%

The contribution credit rate for new hires, rehires and transfers on or after October 13, 2008, will be 4%.

Interest credits will be subject to legal requirements set forth in the Internal Revenue Code, and will initially be equal to the 30-year Treasury rate plus 75 basis points with a minimum interest rate of 5.27%.

Active participants who, as of December 31, 2008, have at least 75 “points” (age + vesting service) will have a one-time opportunity (during an election period established by the Company) to elect to remain in the traditional retirement plan component of the Retirement Plan.

All active participants who are employed on October 13, 2008, and continue to be employed on January 1, 2009, will receive a one-time contribution in the amount of $4,000 to be credited to their cash balance account.  Employees who are eligible to elect to remain in the traditional retirement plan component, and who so elect, will receive credit for the one-time contribution of $4,000 in a special cash balance account which will be subject to the terms of the cash balance plan component and will earn interest credits, but no contribution credits.  This one-time contribution will be made as soon as reasonably practical after January 1, 2009.

By February 28, 2012, a contribution of 1.5% of the employee’s annual base wage will be deposited as a Lump Sum into the employees’ Cash Balance Account. In order to be eligible for this deposit, employees must be on the payroll on February 28, 2012.

By February 28, 2013, a contribution of 1.5% of the employee’s annual base wage will be deposited as a Lump Sum into the employees’ Cash Balance Account.  In order to be eligible for this deposit, the employee must be on the payroll on February 28, 2013.

B.         TRADITIONAL RETIREMENT PLAN COMPONENT

APPLICABILITY OF TRADITIONAL RETIREMENT PLAN COMPONENT:  Beginning December 31, 2008, the traditional retirement plan component shall apply only to active participants who, as of December 31, 2008, have at least 75 “points” (age plus vesting service) and who elect (during a one-time election period established by the Company) to elect to remain in the traditional retirement plan component.  For employees, if any, who satisfy such

41

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

requirements, Retirement Plan benefits will be provided in accordance with the terms of the traditional retirement plan component as set forth in the Retirement Plan document.

C. GENERAL PROVISIONS APPLICABLE TO CASH BALANCE PLAN COMPONENT AND TRADITIONAL RETIREMENT PLAN COMPONENT

Retirement Plan provisions relating to eligibility, vesting, and benefit distributions are set forth in, and governed by, the terms of the Retirement Plan document.  During the term of this Agreement, such provisions shall not be modified in a manner that results in a material diminution in the value of Retirement Plan benefits for employees covered by this Agreement.  The Company may amend the Retirement Plan in any manner necessary to maintain its tax qualified status.

13.6   POST RETIREMENT MEDICAL

During the term of this Agreement, employees who are actively employed on October 13, 2008 and retire on or after age fifty-five (55) with at least ten (10) years of service will be eligible for post-retirement medical benefits, subject to the terms and conditions of the Welfare Plan.

The post-retirement medical calculation for the employer contribution is as follows:

a) For employees who retire from the Company prior to reaching age sixty-five (65), the Company will contribute $260 per year of service.  If an employee retires prior to reaching age sixty-two (62) and has not obtained 85 points as outlined in the Retirement Plan, the $260 is reduced by 5% for each year under age sixty-two (62).  Upon reaching age sixty-five (65), the $260 is reduced to $130 per year of service.

b) For employees who retire from the Company on or after reaching age sixty-five (65), the Company will contribute $130 per year of service.

Employees hired, rehired or who transfer into the bargaining unit after October 13, 2008 will not be eligible for Post-Retirement Medical Benefits as set forth in b) above.

13.7   401(K) PLAN

The NV Energy 401(k) Plan (“401(k) Plan”) shall be incorporated, by reference, into this Agreement for purposes of establishing the level of benefits, and shall govern eligibility and benefits under the 401(k) Plan.  Following is a summary of certain 401(k) Plan provisions, which will be in effect during the term of this Agreement, provided that eligibility, coverage, benefits and all provisions of the 401(k) Plan shall be governed by the terms and conditions of the 401(k) Plan.  The Company may amend the 401(k) Plan in any manner necessary to maintain its tax qualified status.

ELIGIBILITY.  All regular full-time and part-time employees are eligible the first day of the first full pay period after their date of hire.  Temporary employees may join the plan after completing one year of service and having worked at least 1,000 hours in that year.

AUTOMATIC ENROLLMENT:  All new hires will be automatically enrolled at a 3% deferral rate upon initial eligibility.  All new hires will be provided the opportunity to opt-out of the 401(k) Plan prior to initial eligibility.  Employees may elect to stop or change contributions to the 401(k) Plan at any time.  In the absence of any investment election, contributions will be invested 100% in the default investment fund established under the Plan.

VESTING:  There is no vesting period.  Company match is 100% vested upon receipt.

MATCHING CONTRIBUTIONS:  The matching contribution is 100% of the employee’s contribution, to a maximum of 6% of eligible income.

42

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

EMPLOYEES DEFERRAL CONTRIBUTIONS:  Employees’ deferral limit is the lesser of 100% of the employee’s compensation, or $46,000 (for plan year 2008), subject to IRS adjustments and limitations.

“CATCH-UP” CONTRIBUTIONS:  Eligible employees who have attained at least age fifty (50) on or before the close of each Plan Year, shall be eligible to make pre-tax catch-up contributions in accordance with, and subject to the limitations of, IRS Code Section 414(v).

LOAN PROVISION:  Loans may be taken against 401(k) account balances, minimum $1,000, maximum $50,000 (or 50% of total account balance, whichever is less).  General-purpose loans are required to be paid back within five (5) years.  Loans for the purchase of a primary residence are required to be paid back within ten (10) years.  Details regarding loan provisions, including loan fees, interest rates and repayment, are incorporated within the SPR 401(k) Plan Participant Loan Policy.

13.8   LIFE INSURANCE

Life insurance benefits will be provided during the term of this Agreement subject to the terms and conditions of the Welfare Plan.

BASIC LIFE:  The greater of $46,000 or 1.4 times your base pay (maximum $1,000,000).  Benefits from this policy shall be in addition to any other insurance plan.  Eligibility is the first day of month following date of hire.

BASIC ACCIDENTAL DEATH & DISMEMBERMENT (AD&D):  The greater of $46,000 or 1.4 times your base pay (maximum $1,000,000) paid in the event of death resulting from an “accident” as defined by the respective insurance carrier.  Benefits from this policy shall be in addition to any other insurance plan.  Eligibility is the first day of month following date of hire.

BUSINESS TRAVEL ACCIDENT:  All employees covered by this Agreement will be covered by an accidental death and dismemberment policy in the amount of $500,000.  This policy shall apply only when an employee is traveling on Company business outside their regularly assigned work location.  Benefits from this policy shall be in addition to any other insurance plan.  Eligibility is the first day of month following date of hire.

SUPPLEMENTAL LIFE:  The Company will provide a supplemental life insurance program that allows employees desiring such coverage to purchase supplemental life insurance for themselves at group rates.  The following options are available:

●   Employee coverage from .5x to 5x an employee’s base salary (maximum $1,000,000)

●   Spouse’s coverage from $10,000 to $150,000 in increments of $10,000.  However, any employee’s spouse who had an amount of over $150,000 as of December 31, 2004 will be allowed to continue that amount into the future without charge.

●   Child(ren) either in the amount of $5,000 or $10,000.

13.9   LONG TERM DISABILITY

Long term disability benefits will be provided during the term of this Agreement subject to the terms and conditions of the Welfare Plan.

ELIGIBILITY:  Employees may purchase Long Term Disability (LTD) coverage on a voluntary basis through payroll deduction.  Eligibility will be the 1st month following date of hire.  

43

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Temporary employees are not eligible for this benefit.  Payroll deduction will be taken on a post-tax basis the first and second pay periods of each month.

COVERAGE:  Coverage is the lesser of 60% of monthly base earnings rounded to the nearest dollar or the maximum disability benefit ($10,000 a month), less other income benefits as named in the summary description.

LONG TERM DISABILITY (LTD) ELIGIBILITY AND OPEN ENROLLMENT PROCESS:

The eligibility period and enrollment process associated with Long Term Disability (LTD).  The Agreement currently states (in Article 13.8), “The Company will provide a long term disability (LTD) plan, to extend disability benefits at a reduced rate upon termination of benefits described in Article 12.6 (JOB INCURRED INJURIES/SALARY PROTECTION) OR 12.8 (SHORT TERM DISABILITY BENEFIT) ABOVE.  The employee through payroll deduction will pay for premiums for such coverage.  All administrative expenses, exclusive of carrier expense normally absorbed in the rates, will be borne by the Company.  We are not proposing any changes to the language, only administrative practice.

For existing employees, we limit the option to enroll or terminate participation in the LTD plan to an annual open enrollment window, consistent with the health plan open enrollment window.  As consideration, we will change the eligibility date from “completion of probationary period” to be “the first of the month following date of hire” and eliminate the evidence of insurability requirement for employees who enroll during the open enrollment period.  All other exclusions and/or limitations would remain in place pursuant to our contract with the LTD insurance carrier.

Elimination of the “evidence of insurability” requirement will allow an employee to enroll in the LTD Plan during the open enrollment period without question.  However, the insurance Company will not pay benefits for any period of Disability caused or contributed to, or resulting from, a Pre-existing Condition.  “A pre-existing Condition” means any Injury or Sickness, for which the Employee incurred expenses, medical treatment, care or services including diagnostic measures, took prescribed drugs or medicines, or for which a reasonable person would have consulted a Physician within 3 months before his or her most recent effective date of insurance.”

In any event, the Pre-existing Condition Limitation will not apply to a period of Disability that begins after an Employee is covered for at least 12 months after his or her effective date of coverage.

13.10 JOINT BENEFITS COMMITTEE:  A joint benefits committee was established February 1, 2002 for the purpose of reviewing medical, benefits, dependent care, costs, issues and trends.  Joint decisions are made on benefits programs and are binding.  The Committee will consist of the Union Business Manager and four (4) Union members and at least two (2) MPAT employees designated by the Sr. Vice President of Human Resources.  The Committee will be chartered to review health and welfare plans, pension and 401(k) plans during the term of this agreement.

44

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 14

Leaves of Absence

14.1 SHORT TERM LEAVES: Provided the needs of the Company will permit, time off without pay for any period of thirty (30) calendar days or less may be granted employees upon a written application to their department head showing good and sufficient reason for such request.  This shall not be construed as a leave of absence without pay, as the term is used in this Agreement.  A leave of absence without pay is defined as a period of authorized absence from service in excess of thirty (30) calendar days.

14.2 JUSTIFICATION: Leaves of absence shall be granted to regular employees for urgent substantial personal reasons, provided adequate arrangements could be made to take care of the employee's duties without undue interference with the normal routine of work.  Leave will not be granted if the purpose for which it is requested may lead to the employee's resignation.

14.3 DURATION:  A leave shall commence on and include the first work day on which an employee is absent and terminate with and include the work day preceding the day the employee's leave expires.  The conditions under which an employee shall be restored to employment on the termination of his leave of absence shall be clearly stated by the Company on the application for leave form.

14.4 SENIORITY: Except as otherwise provided herein, an employee's seniority shall not accrue while on leave without pay. However, an employee's status as a regular employee shall not be impaired by a leave of absence.  Any period of authorized absence without pay for thirty (30) calendar days or less shall not affect an employee's seniority status.  Upon return from leave, an employee shall return to regular status.

14.5 UNION OFFICE: The Company shall, at the request of the Union, grant a leave of absence without pay for four (4) years or less to an employee who is appointed or elected to any office or position in the Union whose services are required by the Union. The seniority of an employee who is granted a leave of absence under the provisions of this Section shall accrue during the period of such leave. Upon mutual Agreement with the Union, the Company may extend the leave of the incumbent for additional terms up to four (4) years per request. The Company will provide medical coverage for this individual at the single coverage rate. This individual must make the established monthly employee contribution for health coverage.

In the event such employee on leave for the Union Office decides to return to work for the Company, the employee will be returned to the position and location they previously occupied. In the event any employee is displaced by such move, the Company will adhere to Article 5.4 of the Collective Bargaining Agreement. However, it is understood that Recall and Temporary Recall language shall not apply to any contract in affect as of the date of such event. The Company will still retain the right to utilize contractors without Recalling such displaced employees.

14.6 PUBLIC OFFICE: Employees elected or appointed to public office shall be granted a leave of absence for the duration of such appointment or election. Such absence shall not affect accrual rates for seniority purposes; however, sick leave and vacation shall not accrue during this period and group medical benefits shall be paid by the employee at the Company's current premium rate.

14.7 MILITARY LEAVE: A leave of absence shall be granted to employees who enter the armed forces of the United States; however, any such leave of absence and the reinstatement of any such employee shall be subject to the terms of the Selective Training and Service Act of 1940,

45

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

as amended.  Employees who are members of the armed services who are drafted and are called to active duty shall accrue Company seniority while they are absent on military duty.

A regular employee, or a temporary employee who has worked more than one thousand forty (1040) straight time hours, who is a member of the armed forces reserve units, or the National Guard, and who is required to attend annual training sessions, will be granted a leave of absence for the duration of such assignment.  In addition, the Company will pay such employee the amount, if any, by which the remuneration received from the government is less than the base straight time earnings the employee would have received for the same period, not to exceed eighty (80) hours in a calendar year.  Such items as subsistence, travel, uniform and other allowances will not be included in computing the remuneration received from the government.  The Company will require satisfactory evidence of attendance and remuneration received.

14.8 FAILURE TO RETURN FROM LEAVE: If employees fail to return immediately on the expiration of their leave of absence, or if they accept other employment while on leave, they shall forfeit the leave of absence and terminate their employment with the Company.

14.9 FUNERAL LEAVE:  A regular employee, who has worked more than one thousand forty (1040) straight time hours, who is absent from duty due to a death in the employee's immediate family will be excused without loss of regular pay for the time required not to exceed forty (40) hours for making funeral arrangements and attending the funeral, provided the employee attends the funeral, furnishes a death certificate to the payroll department within thirty (30) calendar days.  Additional time may be taken to insure four (4) working days off; any hours in excess of forty (40) hours can be taken as vacation or personal time off without pay.  Immediate family shall mean the employee's grandparents, mother, father, stepmother, stepfather, brother, sister, spouse's grandparents, spouse's parents, spouse's children, spouse, son, daughter, or grandchildren, daughter-in-law, son-in-law, brother-in-law and sister-in-law.

The Company recognizes that there may be instances where the loss of a family member other than those cited in this article causes the same amount of hardship on the employee.  As such, subject to the approval of an HR Representative; funeral leave may be granted for family members not listed in this article. When deciding whether to grant the leave; the HR Representative will conduct an analysis with a presumption that the leave is warranted.

Furthermore, this does not forego the responsibility for the employee to adhere to the attendance policy. The employee must notify the immediate supervisor and subsequently contact an HR Representative for approval.

In addition, the Union and Company agree after a complete and thorough investigation, any employee found to have manipulated this article for other than what it is intended for will be disciplined up to and including termination.

14.10 JURY DUTY:  When regular employees, or temporary employees who have worked more than one thousand forty (1040) straight time hours, are absent from work in order to serve as a juror or to report to the court in person in response to a jury duty summons or to report for jury examination, they shall be granted pay for those hours spent in such service during their regular work day or regular work week. Employees shall furnish the Company with a statement from an officer of the court setting forth the time and days on which they reported for jury duty and their compensation due or received for+ jury duty.

14.11 SUBPOENA:  If employees are absent from work, in order to serve as a witness in a case in a court of law to which they are not a party, either directly or as a member of a class action suit, and where such absence is in response to a legally valid subpoena or its equivalent, the employee shall be granted leave with pay for those hours for which the employee is absent

46

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

from work during the employee's regularly scheduled working hours, provided the employee submits evidence of such service as a witness, detailing the time required to testify.

14.12 FAMILY LEAVE:  Employees who are eligible for benefits but have less than one (1) year of service with the Company are entitled to forty-five (45) calendar days of unpaid family leave to use for the birth or adoption of a child.  Vacation pay may be used for a portion of this leave of absence but will not extend the leave to more than forty-five (45) calendar days.

14.13 FAMILY AND MEDICAL LEAVE:  Employees who are eligible for benefits and have one (1) year or more of Company service may be entitled to twelve (12) weeks of unpaid leave in accordance with the Federal Family and Medical Leave Act (FMLA) of 1993.  Employees on any form of approved FMLA leave are required to use any available accrued sick leave while on FMLA leave and any such employees on FMLA leave may not elect to take unpaid FMLA leave while having accrued sick leave available.  Employees on any form of FMLA leave who have both accrued sick leave and vacation available will be allowed to choose whether to apply sick leave or vacation to their leave provided that such leave is not taken unpaid if accrued sick leave is available.

-  -

47

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 15

General Provisions

15.1 SUPERVISORY RESPONSIBILITIES IN EMERGENCY CONDITIONS: It is the intention of the Company that supervisors shall generally confine their activities to the supervision of the work or operations being performed. In certain instances, should emergency conditions arise, it may be necessary for them to perform those tasks normally assigned to bargaining unit employees. Under ordinary circumstances, such instances will very rarely occur, but since the safety of personnel or Company property may be in jeopardy, it must remain management's prerogative to determine when conditions require the actions described above.  In the same manner it is the intention of management that the "chain of command'' be adhered to, by both supervisors and bargaining unit employees. However, in the case of emergencies, there will be occasions when it may be necessary for a senior supervisor to bypass normal chain of command in order to prevent difficulties. Common sense and good judgment must be exercised in applying these paragraphs.

For Facilities classifications only: Intended to expand Article 15.1. Due to the inherent nature of the facilities department, Management will have increased flexibility to provide necessary support and assistance without violating terms of this agreement.  This flexibility is not intended to replace bargaining unit employees.

15.2 NEW CLASSIFICATIONS/WAGES: Any new rate covering work normally performed by employees within the bargaining unit shall first be discussed with the Union and the rate established for such work shall be that mutually agreeable to both parties. When advances in technology or other changes that materially affect job duties and responsibilities, the Union and the Company will agree to revise job descriptions as needed.

15.3 REMOVING LETTERS OF DISCIPLINE: Any employee, who receives a written letter of reprimand which is a part of the personnel file maintained in the Company's HR office, may, after three (3) years from the date of such letter, request in writing to have the letter removed. Upon such written request, the Company shall remove the letter and return it to the employee.  If the behavior that warranted the letter has changed or been corrected, the employee's current supervisor can remove the letter from the employee's personnel file by documenting this change in behavior and providing written authorization to HR. Letters of reprimand older than three (3) years will not be considered for purposes of placement, promotion or discipline.  Situations that require a review of an employee file will also prompt the Company to remove any letters of reprimand three (3) years or older.

15.4 FACILITIES: The Company will provide on its premises clean, sanitary and reasonably comfortable rest and wash rooms, including first aid cots for female employees, together with a proper place for storing lunches carried by employees, and reasonably safeguarding employee's out-of-door clothing and necessary personal effects on the Company's property during the time employees are on duty. The Union agrees to cooperate with the Company in the maintenance of these facilities.

15.5 FAMILY ISSUES:  The Company and the Union recognize that work/family issues will continue to be at the forefront of workplace activities. As such, the Company and the Union have agreed to address the issues of job sharing, telecommuting and other alternative work schedules or programs which allow both the Company and employee maximum flexibility without jeopardizing customer service. These issues will be addressed through labor/management meetings and may be initiated on a case-by-case basis.

15.6 LABOR / MANAGEMENT MEETINGS: The Company and the Union agree to hold periodic meetings to discuss matters, which are covered by the Agreement. These meetings will be held

48

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

on Company premises during work hours and shall be held as needed, with thirty (30) calendar days notification from either the Company or the Union.  The number of employee attendees who are covered by the Agreement shall be limited to the stewards and other employees reporting to the Company premises designated as the site of a particular meeting. Both the Company and Union recognize the value in formally convening to discuss issues that affect departmental policies, procedures, and collective bargaining provisions.  The Company and Union agreed to continue holding departmental labor/management meetings as a forum to clarify; address interests, and problem-solve solutions that mutually benefit all employees. The Company recognizes the value of participation and input from all its employees and the Union's facilitation of this process is critical to our mutual success.

15.7   INCENTIVE PROGRAMS: The Company and the Union agree to discuss all incentive programs which are an addition to base wages.

15.8 PROJECT TEAMS / COMMITTEES: The prevalence of project teams/committees that require the specific skills and abilities possessed by employees in bargaining unit jobs is increasing each day.  The Company acknowledges that it must obtain agreement from the Union before assigning bargaining unit employees to any project teams/committees which are outside of the employee’s regular duties, particularly when the project team/committee’s task could affect the working conditions of employees represented by the Union. Any such assignment shall be staffed from qualified volunteers on a project by project rotating basis. The Company further agrees to notify the Union when assigning an individual bargaining unit employee to a special project which may last longer than 1040 hours. In addition, team member(s)’ wages and/or benefits are expected to be only those described in the current CBA. If the Company wishes to extend additional incentives/bonuses to bargaining unit employees on the team/committee, the Company will negotiate with the Union before extending any such offers to bargaining unit employee(s).

49

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ARTICLE NO. 16

Working Rules

16.4      APPRENTICE PROGRAM (Applicable only in T&D and Generation): The NV Energy Apprenticeship Training Program, revision I, dated December 20, 1982, shall be incorporated by reference into this Agreement and any modifications or amendments must be handled in accordance with Article 17 (TERM OF AGREEMENT)

Joint Apprenticeship Training Programs shall be established by the Company and the Union, registered with the Nevada State Apprenticeship Council and shall be administered in accordance with the standards set by the Nevada State Apprenticeship Council.  The programs which are to be included in the training programs require the recommendation of the applicable Joint Apprenticeship Committee(s) and approval and acceptance by the President of the Company, and the Business Manager of the Union.

Joint Apprenticeship Training Committee: Each Joint Apprenticeship Committeeshallbe comprised of an equal number of members appointed by the Company and the Union, the apprentice trainer present as a neutral, and an apprentice training supervisor appointed by the Company who will serve as Chairman of the Committees to develop, coordinate and administer the programs. The Joint Apprenticeship Committees shall have the responsibility for investigating problems of apprenticeship training such as standards of progress, methods of testing and scoring progress of apprentices and procedures for demotion or termination when apprentices fail to meet established standards or requirements. Any motions made by one side must be seconded by the other side; all motions shall be by majority vote.

The Committee members appointed by the Union shall receive their rate of pay for actual time spent in the Joint Apprenticeship Committee meetings called by the Chairman.

Part of the Apprenticeship curriculum shall be the history of the IBEW, not to exceed ten (10) class hours per apprenticeship. The Union will be responsible for supplying the Company with all necessary training materials.

APPRENTICE/JOURNEYMAN RATIO: The ratio of apprentices to Journeymen shall not exceed one to three (1:3) or a major fraction thereof. The work performed by apprentices shall be assigned and reviewed by the appropriate working foreman or designated Journeyman, subject to the approval of the appropriate supervisor.

FIRST YEAR APPRENTICE:  An apprentice who has been in the apprenticeship for a period of less than twelve (12) months shall not be assigned any work which, in the opinion of the immediate supervisor, is hazardous.

TWENTY-FOUR (24) MONTH APPRENTICE: Any apprentice who has been in the apprenticeship for a period of less than twenty-four (24) months, shall not work on conductors energized in excess of seven hundred fifty volts (750). After that period, and after successful completion of Hotstick School, the apprentice may work under the direct supervision of a Journeyman on all voltages, which, in the opinion of the immediate supervisor, would not create an undue hazard at that stage of the training.

APPRENTICE LINEMAN:  An apprentice lineman who has completed at least twenty four (24) months as an apprentice with the Company may be used to install and maintain private area lighting on existing poles and will be assisted by a groundman for this work, contrary to language elsewhere in this Agreement.  Private area lighting, which requires the excavation for an installation of a pole, shall be accomplished by a special line crew.  The assignment of any apprentice to the private area lighting program shall be on a non-permanent basis and rotated in accordance with the apprentice program.

50

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

16.6 TOOLS, EQUIPMENT AND WORK CLOTHES (Applicable only in T&D and Generation): An employee shall initially furnish hand tools which are reasonable and acceptable to the Company and necessary for the work to be performed. The Company will furnish all protective equipment including but not limited to, FR clothing, leather gloves, hard hats, safety glasses, safety shields, and any other tools or clothing required by OSHA, at no cost to the employee.

The Company will provide a safe and dry place for the storage of employees’ tools. (Safe and dry means a storage box that can be locked.) The employee shall be responsible for the above listed tools and must ensure that they have been securely stored at all times. Properly secured tools that are stolen shall be replaced promptly by the Company. Tools that are worn out or destroyed in the normal and proper operation of that tool will be repaired or replaced by the Company.

16.7 WELDING REQUIREMENTS (Applicable only in T&D and Generation): When an employee performs welding work above ground floor or around energized electrical apparatus, there shall be aqualified observer present.

16.9   TEMPORARY APPOINTMENTS: Wherever a vacancy occurs in any job classification, the Company may temporarily fill such vacancy by appointment for a maximum of forty-five (45) calendar days. Upon notification, that such appointment will last longer than forty-five (45) calendar days, the Company will fill the position with the qualified senior volunteer.

After sixty-five (65) weeks from the date of the original vacancy, temporary appointments will be filled following provisions of Article 7.3 Staffing Vacancies.

This article is not meant to circumvent normal staffing guidelines.

When an employee relieves an employee of a higher classification for time worked, the employee shall receive the rate of pay for the higher classification for the time worked in the higher classification.

Represented Employees shall receive a 10% pay increase when temporarily appointed to the General Foreman classification.

It is understood that an employee temporarily appointed to the Lead Lineman classification in “Transmission and Distribution – Lines Department” must abide by these additional restrictions:

■   Only work extension of shift

■   Only accept trouble calls up to one (1) hour prior to end of shift

■   No other overtime is permitted unless no other foreman is available for such overtime

The following restrictions will only apply if the Company has twenty-four (24) hour coverage or more than two (2) shifts in any combination, or the Company eliminates overtime and reduces schedules to only straight-time coverage. (i.e. no extension of shift):

An employee will not be temporarily appointed to a higher classification when employees of that classification who normally report for work at the same location are able and available to do the work for which the temporary appointment is intended.

If a shift employee, for reasons other than a scheduled vacation, is unable to report to work, an employee (who is on the designated days off) from the same classification, including relief employees in that classification, who normally reports for work at the same location will be called by telephone to cover the vacant shift. If an employee, who is on the designated days off, holding the same classification who normally reports for work at the same location is not available, the employee of the same classification who normally reports for work at the same

51

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

location on the previous shift will work half of the vacant shift and the employee of the same classification who normally reports for work at the same location on the shift following the vacant shift will work the remaining half of the vacant shift. If for any reason these arrangements cannot be made, the Company may temporarily appoint an employee to cover the vacant shift.

The Company may temporarily appoint a shift employee for scheduled vacations, provided that all overtime involved from such temporary appointment be worked by an employee holding the classification who normally reports for work at the same location from which the vacation was granted.

It is understood that if the relief operator in Generation is available, that operator may be used to relieve as described under "Exhibit I (CLASSIFICATION DESCRIPTIONS)''.

GENERAL FOREMAN WORKING (TEMPORARY APPOINTMENT ONLY)

An employee assigned on a temporary basis at the Company’s discretion, to assume a leadership role under any combination of the following circumstances:

■   On special projects when required to direct crew operations and coordinate all aspects of construction, maintenance and repair of company facilities.  Will aid in the design of facilities and also participate in the planning stages of such projects,

■   Replace a supervisor who will be absent from their duties.

■   When directing the work of other foremen and their crews (foreman over foreman),

■   Assume other duties as deemed appropriate by management except for the following:

1.   time sheet approval

2.   vacation approval

3.   completing performance appraisals (may give input)

4.   approving meal tickets and credit card receipts

5.   approving accounts payable items

6.   scheduling of overtime

7.   any function that may lead to discipline

16.10 REQUIRED LICENSES, PERMITS, CDLs (Applicable only in T&D and Generation): Employees required to operate any motorized vehicle or equipment on public roadways in the normal course of employment shall be required to possess and maintain all licenses and permits required by state and/or federal laws.  The Company will provide suitable training to all employees required to operate equipment or vehicles where a commercial driver’s license (CDL) is required and shall issue a certificate upon satisfactory completion of the driver training and testing program.  Employees who by their regular work assignments, may be required, as a condition of employment and Nevada Revised Statue, to maintain an active commercial driver’s license (CDL), shall be provided reasonable time with pay during their regular working hours, to obtain or renew such licenses provided such activities are not a result of the employees violation of any state or federal law or public policy.

16.11 VESSEL CONDITIONS (Applicable only in T&D and Generation): Employees entering vessels/compartments will comply with OSHA standards addressing temperature and duration of exposure.

52

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

  ARTICLE NO. 17

Term of Agreement

17.1 DURATION:  This Agreement shall take effect on September 1, 2011, and shall continue in effect for the term September 1, 2011 through January 31, 2013, and shall continue in full force and effect from year to year thereafter unless written notice of termination shall be given by either party to the other at least sixty (60) calendar days prior to the end of the then current term.

17.2 AMENDMENTS:  If either party desires to amend this Agreement, it shall give notice thereof to the other party at least sixty (60) calendar days but not more than seventy (70) calendar days, prior to the end of the then current term, and the party desiring to amend or revise this Agreement shall submit to the party so notified a detailed outline of the Articles and Sections to be amended or revised at the time the notice is given, except and unless otherwise mutually agreed to by the parties during this period of notice defined herein. Negotiations on the amendments or revisions shall take place, so far as possible, in the sixty (60) calendar day period prior to the end of the then current term. Failure of the parties to agree on such proposed amendment or revision shall not cause termination of this Agreement unless either party has given notice of termination as provided in Article 17.1 above.

17.3 PROVISIONS IN CONFLICT WITH THE LAW: In the event that any provision of this Agreement shall at any time be made invalid by applicable legislation, or be declared invalid by any court of competent jurisdiction, such action shall not invalidate the entire Agreement, it being the express intention of the parties that all other provisions not made invalid shall remain in full force and effect.

17.4 CHANGE IN COMPANY STATUS: This Agreement shall be binding upon the successors and assigns of the Company, and no provisions, terms or obligations herein contained shall be affected, modified, altered or changed in any respect whatsoever by the consolidation, bankruptcy, merger, sale, transfer, reorganization or assignment of the Company, or by any change in the legal status, ownership or management thereof.

17.5 EFFECTIVE DATE OF AGREEMENT: It is mutually agreed by and between the parties signatory hereto that the Agreement dated February 1, 2008 is superseded by this Agreement dated as of September 1, 2011 except as otherwise expressly provided herein, the provisions of this Agreement shall be effective September 1, 2011.

53

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

IN WITNESS WHEREOF, the parties hereto have executed this Agreement effective September 1, 2011.

 /s/ Paul Kaleta

 Paul Kaleta

 Corporate Sr. Vice President & General Counsel

 NV Energy

Local Union 396 of the International

Brotherhood of Electrical Workers (AFL-CIO)

 /s/ Charles W. Randall

Charles W. Randall

Business Manager/Financial Secretary

 IBEW Local 396

Negotiating Committee

 NV Energy IBEW Local 396

David Lonergan                                                                                                                                Charles W. Randall

                                                                    Ryan Bellows                                                                                                                                       Jesse Newman

                                                                 Trudy Haszlauer                                                                                                                               Jeremy (Frog) Newman

                                                                                                                                                                                                                                      Casey Wills

                                                                                                                                                                                                                                         Marc Orr

                                                                                                                                                                                                                                Shannon Skinner

                                                                                                                                                                                                                                  Karl McGlothlin

                                                                                                                                                                                                                                    Wayne Baca

54

EXHIBIT III

International Brotherhood of Electrical Workers

Local Union No. 396

CHECK OFF AUTHORIZATION

I, _______________________________________________________________, herewith authorize  (print name)       (employee no.)

NV Energy to deduct initiation and/or reinstatement fees and monthly dues owing to the International Brotherhood of Electrical Workers Local 396, in accordance with the Constitution and By-Laws of the Union, and direct such amounts so deducted be sent to the Secretary-Treasurer of the Union for and on my behalf.

When the full amount of the initiation or reinstatement fee has been withheld from my earnings, such authorization for deduction of initiation or reinstatement fee only shall be null and void, and shall thereafter have no further force or effect.

This agreement between the Union and I shall be in effect from year to year unless I give written notice to the Union of my desire to terminate my membership with the Union.  The Union will notify the Company on a biweekly basis if necessary of those employees who wish to revoke this deduction; such deductions will cease in the pay period following receipt of such notice from the Union.

It is recognized that neither the Company nor the Union shall be under any liability to me, the undersigned, with respect to the deductions provided herein.

Signed _______________________________________________________________________

Date _________________________________________________________________________

55

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

EXHIBIT IV

TEMPORARY LAYOFF PROVISIONS

The following provisions shall apply relative to a temporary layoff, as referenced in Article 5.4 (LAYOFF PROVISIONS):

NOTIFICATION:  Should the Company initiate a temporary layoff, affected employees shall be notified in writing as soon as possible, and will have three (3) business days to indicate their interest for consideration in the layoff.

ELIGIBILITY:  Temporary layoffs, out of line of seniority, shall be strictly voluntary.  If there are more volunteers than needed within a classification, selection shall be determined by highest Company seniority of the interested employees. If there are no volunteers, the Company shall explore other alternatives that may satisfy the temporary layoff situation.

TIME FRAME:  A temporary layoff shall be for the stated time period or less, as indicated in writing at the time of notification. If, during the temporary layoff, the Company recognizes that the layoff may extend beyond the original time frame, employees in layoff status shall be given the option to extend or return to work.  If the temporary layoff ends before the stated time frame, employees will be notified immediately, and expected to return to work the next day unless the Company approves other arrangements.

PAY:  Employees shall be paid approximately 70% of their current income, which includes income received from unemployment compensation as a result of the layoff. The following formula shall be used to calculate an employee's gross wages while on temporary layoff:

Base rate  x  40 Hrs.  x  70% -  Unemployment Income  = Weekly Gross Wages

For the purpose of this calculation, the unemployment compensation amount will be subtracted to arrive at gross wages even if the employee does not receive this benefit.  The exception to this provision will be for the first week of the temporary layoff, when employees will be required to serve a waiting week for unemployment compensation.  For this initial week, employees will be paid 70% of their base rate.

VACATION: No adjustment to vacation accrual shall be made during the first sixty (60) calendar days of a temporary layoff.  However, once the sixty (60) calendar days period has elapsed, an employee's vacation accrual shall be adjusted and treated as any other leave, as outlined in Article 11.4 (VACATION ADJUSTMENTS).  Employees in layoff status and unable to use their vacation allotment for that year, the unused vacation shall be automatically carried over to the next year.

SICK LEAVE:  Employees shall continue to accrue sick leave monthly, as if they were working.  However, employees will not be eligible to use sick leave or short-term disability during the period for which they are on temporary layoff.

HOLIDAYS: Employees shall not be entitled to holiday pay while on temporary layoff.  The only situation that would warrant holiday pay is if they began or were recalled from temporary layoff during the week of a holiday.

Example:

If the temporary layoff begins on Tuesday of a week with a Monday holiday, the employee would

receive holiday pay for that day.

These provisions do not apply to the floating holiday, as the employee would be allowed to reschedule the day at a future time. If as a result of a temporary layoff an employee is unable to schedule their floating holiday, they will be allowed to carry this holiday into the following year.

SENIORITY:  An employee's seniority shall continue to accrue during the period of layoff.

56

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

BENEFITS: An employee’s benefits shall remain the same during the period of layoff. Employee’s monthly contribution will be deducted from these bi-weekly checks.

PROMOTIONAL OPPORTUNITIES: Employees shall be eligible to indicate their interest in promotional opportunities that may arise during the period of layoff. However, they must individually assume the responsibility of meeting appropriate deadlines for consideration.  Any employee awarded a promotion or transfer while on temporary layoff, will be returned to work immediately.

RECALL: Should the Company need to recall employees in a specific classification prior to the previously stated date; employees shall be recalled by Company seniority on a volunteer basis. If there are no volunteers to return, inverse seniority will be used to satisfy these requirements.  Any issues delaying an employee's return to work will be addressed on an individual basis. However, the monetary benefits associated with a temporary layoff will end on the date of recall.

57

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

CLERICAL

ARTICLE NO.  4

Union Activity

4.3 CONTRACTING WORK:

In case the Company should contract any type ofwork customarily performed by bargaining unit employees, the Company shall, before awarding such contract, advise the contractor that the work is to be done under not less than the terms and conditions pertaining to hours and wages set forth in this Agreement.  Upon award of such contract, the Company shall notify the Union in writing within thirty (30) calendar days of any and all contracts awarded of such contractor and the nature of the work being performed.

58

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

CLERICAL

ARTICLE NO.  5

Status Designation

5.1 PART-TIME: A part-time employee is one who is hired for a job that is of indefinite duration and whose regular work schedule is not more than thirty (30) hours per week. The number of part-time employees shall not exceed the rate of one (1) part-time employee to five (5) regular employees (1:5) within the same classification. A part-time employee shall not displace any regular employee covered under the terms of this Agreement and shall be limited to non-field type activities.

If a part-time employee is offered and accepts a regular position, the employees part-time hire date will be used for purposes of seniority and all other benefits.

Benefits for Part-Time Employees:

To participate in the benefits programs, employees must work a minimum of twenty (20) hours per week. The benefits stated below will have the appropriate premium allocation between Company and the employee and eligibility will begin the first of the month following the date of hire.

●   Medical, Dental, Vision, and Prescription Drug Program

●   LTD

●   401(k)

●   Basic Life

●   Basic Accidental Death & Dismemberment (AD&D)

●   Business Travel Accident

●   Pension (see Article 13.1 ELIGIBILITY)

●   Dependent Care Flexible Spending Account (DCFSA)

●   Health Care Flexible Spending Account (HCFSA)

●   Supplemental Life

All benefits for which part-time employees may be eligible are set forth in this article.

Part-time employees monthly premium for the Medical, Dental, Vision and Prescription Drug Programs will be calculated according to the amount of hours worked and based on the following formula.

1.   Twenty (20) hours per week = one-half (1/2) time

2.   More than twenty (20) but less than thirty-one (31) hours per week = three-quarter (3/4) time.

Part-time employees who work twenty (20) hours per week will pay 150% of the monthly healthcare premiums.

Part-time employees who work more than twenty (20) hours per week but less than thirty-one (31) hours per week will pay 125% of the monthly healthcare premiums.

The following language covers Clerical, Part-Time employees:

●   At least two (2) days off shall be consecutive during the workweek; however, the days off may not be Saturday and Sunday. (Ex:  The employee’s day off may be Wednesday and Thursday).

●   At least two (2) hours in any one-day shall constitute the workday.

59

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

●   Shift differential will apply as usual.

●   Bilingual pay will apply at $15.00 per pay period.

●   Full-time employees will be called out first.  During emergency situations, full-time employees may not be called-out first in the interest of coverage.

●   At least twenty-four (24) hour notice will be given for change in work schedule.

●   All language relative to meals in Article 6 would apply after completing eight (8) hours of continuous work.

●   For the purpose of processing step increases, 1040 hours worked will be considered equivalent to “six months,” as stated in Exhibit II, Schedule of Wage Rates.

●   If scheduled to work more than thirty (30) hours per week, except if the hours worked in excess of thirty (30) hours are due to classroom training will receive overtime at Time and a Half

Employees who are in classroom training may work up to forty (40) hours per week without incurring overtime pay.

60

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

CLERICAL

ARTICLE NO.  6

Working Hours and Rates of Pay

6.1 DEFINITIONS:

SHIFT: Hours of work.

SCHEDULE: Days and hours of work.

WORK DAY: Eight (8) hours in any one (1) day shall constitute the work day; however the Company and Union may enter into Agreements which establish alternative work schedules involving work days which have more than eight hours.

WORK WEEK: Except as provided for part-time employees, the basic work week shall consist of five (5) consecutive work days, regularly scheduled between the hours of 12:01 am, Monday, and 12:00 midnight, Sunday, provided that no employee shall be assigned, as part of a regular work schedule, to work on Saturday or Sunday, unless such employee voluntarily requests to work such schedule, or is hired or has requested reclassification for such purpose, and provided further, that employees in the Field Service Representative and Service Dispatcher classifications may be required, as part of their regular work schedule, to work on Saturday.  The basic workweek of regular day-shift employees shall be from Monday through Friday and reflect a schedule of forty (40) hours of straight-time work.

REGULAR DAYS OFF: Days off shall be consecutive, however, they may not be within the basic work week.

REGULAR DAY-SHIFT EMPLOYEES: Regular day shift employees are those employees who are assigned to shifts, which are established on a Monday through Friday schedule and work a shift, which begins between the hours of 7:00 a.m. and 11:59 a.m.  When mutually agreed to by the Union and Company, the day shift starting time may be scheduled as early as 6:00 a.m. to take advantage of daylight hours. Leads classified in the Field Service and/or Meter Reading department(s) may be scheduled as early as 5:00 a.m.

SHIFT EMPLOYEES: Shift employees are all employees not defined as regular day-shift employees.

SHIFT DIFFERENTIAL:  An incremental increase for working on a second or third shift.

SHIFT DESIGNATIONS:No shift periods shall start between the hours of 12:01 a.m. and 5:59 a.m., unless mutually agreed to by Memorandum of Understanding between the Company and the Union.  The following designations shall apply:

FIRST SHIFT:  All eight (8) hour shift periods regularly scheduled to begin at 6:00 a.m., or thereafter but before 12:00 noon shall be designated as first shifts.

SECOND SHIFT: All eight (8) hour shift periods regularly scheduled to begin at 12:00 noon or thereafter but before 8:00 p.m., shall be designated as second shifts.

THIRD SHIFT: All eight (8) hour shift periods regularly scheduled to begin at 8:00 p.m., or thereafter but before 12:01 a.m., shall be designated as third shifts.

6.3   OVERTIME:  In computing overtime, intermission taken out for meals served other than on the job shall be deducted, and any holiday or vacation paid in that pay period will be considered as time worked.

NO PYRAMIDING OF OVERTIME:  The employee will only be entitled to the highest single premium rate applicable to the work assigned by the CBA.  There will be no pyramiding of overtime.

61

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TIME AND A HALF:  Except as otherwise provided in this Article, the following situations shall require payment at one and one-half (1-1/2) times the regular established wage rate:

• Time worked in excess of eight (8) hours per day.

• Time worked in excess of any five (5) scheduled workdays.

• Work scheduled in the three (3) hours immediately preceding the normal starting time.

• Employees scheduled to work on an observed holiday.

DOUBLE TIME: Except as otherwise provided in this Article, the following situations shall require payment at two (2) times the regular established wage rate:

• Employees who are scheduled to work within the first five (5) hours of the eight (8) hour period immediately preceding the normal starting time regardless of the day of the week.

• Employees who work on the second day of a two-day off period with an overtime minimum.

6.5 OVERTIME EQUALIZATION: The Company will endeavor to distribute overtime work as evenly as possible among those employees qualified and desiring such work.  Each department will create policies and procedures for overtime equalization through labor/management meetings.  For purposes of distributing overtime, the Company will maintain and post overtime lists in each major sub-department office indicating time offered, time worked and other information for inspection by the employees and the Union.

6.6 BI-LINGUAL REPRESENTATIVES: Employees in Customer Service who are designated as bi-lingual representatives shall be paid a thirty-dollar ($30) bonus on a bi-weekly basis.  This bonus will be paid when the employee uses sick leave or vacation, but will not be paid when the employee is on disability or using Workers Compensation. New hires will be offered bilingual positions with the understanding that they must pass the bilingual exam during the probationary period. If they do not pass the bilingual exam they will be terminated before the completion of the probationary period. Once employees are certified bilingual employees, they are not allowed to decertify and must remain in the bilingual shifts offered in Customer Service. Existing Customer Service employees may decertify bilingual status before the start of the next shift bid. Employees must wait a year to be certified again and held to this new agreement. Any new existing Customer Service employee that wants to become a certified bilingual employee will be held to this new agreement.

6.8 CALL-OUTS:

TWO HOUR MINIMUM: Employees called out for overtime duty shall receive at least two (2) hours pay.  Employees called out who work into their regular shift shall be paid the appropriate overtime premium for at least two (2) hours and straight time for the remainder of the shift.  The two (2) hour call-out minimum applies but does not change the normal starting time.

Example:

An employee who is called out one (1) hour before the shift would be paid two (2) hours of

double time and seven hours of straight time.

62

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

6.10 REQUIRED NOTICE FOR OVERTIME:

SCHEDULED OVERTIME: In scheduling overtime work, a minimum of fourteen (14) hours notice is required, prior to the start of any overtime for a particular day, and before leaving the work site on a regular work day. Without this notice, such work will be considered as a call-out. It is understood that overtime, when worked as an extension of a regular shift, does not require such notification.

Example:

An employee assigned to a 7:00 am to 3:30 pm shift and held over for overtime and is

notified to work the next day  (his/her day off) at 7:00 am. If notification is

given in the first two (2) hours of held over overtime, this overtime is considered scheduled.

CANCELING OVERTIME: A minimum of twelve (12) hours notice is required on canceling pre-scheduled overtime. When customer arrangements are involved, the Company must provide twelve (12) hours notice prior to the employee's next normal starting time. When such notice of cancellation of pre-scheduled overtime work is not given in accordance with the above, employees involved will be paid for two (2) hours at established overtime rates if they report and are retained for work. When such notice of cancellation is not given in accordance with the above, but employees are later notified of work cancellation, they will be paid for two (2) hours at established overtime rates. If they report and are not retained for work, they shall receive pay for two (2) hours at established overtime rates

6.14 VEHICLE USAGE:  No employee shall be required to operate a personal vehicle in the course of employment as a condition of employment.  Employees shall be required to obtain a Nevada driver's license whenever operation of a Company provided vehicle is a requirement of the job.

Employee's who are authorized to use personal vehicles in the course of their employment shall be compensated for use of the vehicle at a rate equal to the Internal Revenue Service (IRS) maximum mileage expense.

Example #1:

If employees are assigned to work at an office other than their normal base reporting point, after they have already reported for work at their normal base reporting point, and no Company vehicle is available, they shall be compensated for use of their vehicles for the actual miles traveled from office-to-office as designated on the chart attached at the rate equal to the Internal Revenue Service (IRS) maximum mileage expense.  If they return home directly from that office, they shall not be compensated for the miles traveled from the office to their home.

Example #2:

If employees report for work at an office other than their normal base reporting point directly from home, they shall not be compensated for the miles traveled from their home to the office nor from the office to their home.  Only those miles traveled from office-to-office are eligible for compensation.

Any employee who is authorized the use of a private vehicle during the course of his or her employment shall be provided liability protection under the terms of the public liability and property damage insurance policy maintained by the Company as if the employee were operating a Company-owned vehicle except that if the laws of the State of Nevada establish that the personal insurance policy of the employee shall be the primary insurance, then such consideration shall be first applied.  In the event of an accident involving an uninsured motorist where damages to the employee’s private vehicle are not recoverable from the responsible party, then costs of repairing such damage shall be reimbursed by the Company.

63

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Mileage Chart:

	CLK	DI	HCUST	HSVC	IND	LGHLN	N LV	PRSN	RG	RYAN	SPRNG	SNRIS	S SVC CTR
CLARK	0	5	7	5	13		13	14	64	19	14	6	12
DESERT INN	5	0	14	16	6		9	6	59	14	9	4	11
HEND CUST	7	14	0	2	14		22	22	71	23	20	13	16
HEND SVC	5	16	2	0	12		20	20	69	21	18	11	15
INDUST RD	13	6	14	12	0		10	4	54	9	6	7	8
LAUGHLIN						0		107					97
NLV	13	9	22	20	10		0	10	51	6	11	9	13
PEARSON	14	6	22	20	4	107	10	0	58	13	3	12	7
RG PLANT	64	59	71	69	54		51	58	0	45	58	58	52
RYAN SVC	19	14	23	21	9		6	13	45	0	17	13	16
SV SVC	14	9	20	18	6		11	3	58	17	0	13	6
SUNRISE	6	4	13	11	7		9	12	58	13	13	0	16
S. SVC CTR	12	11	16	15	8	97	13	7	52	16	6	16	0

6.15 REQUIRED NOTICE: The Company will provide two (2) days notice when an employee is assigned to work in an office other than the employee's base reporting point.  If the Company does not provide two (2) days notice, the employee shall be paid one (1) hour at time and one-half (1-1/2) for each day until the two (2) day notice period has been satisfied.

6.16 REPORTING LOCATION: Employees in the bargaining unit shall report for work at regularly established Company headquarters, shall travel from job to job and between job and headquarters on Company time and shall return to the regularly established Company headquarters at the conclusion of the day’s work. The Company retains the right to assign and/or reassign the employees to reporting locations.

6.18            SHIFT BID POLICY

Semi-Annual Application Process

Full-time regular and part time (not temporary) employees in the Call Center and Commercial Offices will have the opportunity to complete a Shift/Location Preference Application form on a semi-annual basis, during the months of April and October.  These requests will be valid for the six (6) month period following the month in which the application is filed. Shift/location changes will be made on the basis of Company seniority between employees in the same classification; Lead Person, CSR provided that the employees are capable of interchanging while ensuring full protection of operational efficiencies under all circumstances and conditions. The Shift Bid committee shall consist of Union Stewards and Team Leaders. There shall be at least three (3) meetings, which consist of: preparation meeting, selection meeting and post meeting.

   Filling Vacancies

When a vacancy occurs, by reason of an increase or decrease in manpower requirements due to a transfer, promotion, or termination, preference will be given to the applicant with the longest Company seniority who has made application in accordance with the above provisions.  The vacant shift, which is created by moving the successful applicant, will be available for consideration only to employees at that location.  A newly hired employee will fill the final vacancy, created by any subsequent moves.

Due to the requirements of efficient operations, there may be circumstances where the senior applicant cannot be accommodated and must remain on his/her shift/location or be reassigned to a less desirable schedule.  In each such instance, a meeting will be held with the applicant, a steward if requested, the supervisor, the appropriate HR Partner and representative(s) of the Union to discuss the need for such an assignment.  This meeting will detail the Company’s concerns and describe a plan of action to correct the situation. The Company will identify the timeframe the employee will be required to remain on this less

64

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

desirable schedule.  If the above stated timeframe is to exceed six (6) months, a formal hearing will be conducted to review and discuss related issues. Employees transferred to another shift/location due to a reduction in departmental requirements may make location preference within one (1) calendar week of the beginning of this new assignment and such request will be considered timely until the next application period.

   Probationary Employees

Probationary employees will be assigned to shifts/locations for a minimum of six (6) months, and will not have access to shift/location change provisions until the six (6) month period has been satisfied and then only at the next application period or if a vacancy occurs before the next application period, however their shift is assigned based on classification seniority.

Newly Assigned Employees: Employees entering a new classification will be assigned to shifts/locations until such time that the supervisor determines that they have completed all of the necessary training, at which time they will be assigned according to seniority in their classification to a vacant shift/location.  They will then have access to the shift/location change provisions at the next application period or if a vacancy occurs before the next application period.  They may make application for shift/location preference within one (1) calendar week of the time that their training is completed and such request will be considered timely until the next application period.

Temporary and Part-Time Employees: Temporary and part-time employees will not have access to shift/location change provisions until they assume regular status crediting actual time worked for purposes of this Agreement.  These employees will be eligible for consideration during the next application period. However shifts are assigned based on classification seniority for part time employees only.

Hardship Requests: It is recognized that, under certain circumstances such as serious home conditions or ill health, it may become necessary for an employee to request a temporary shift/location change. Such request shall be made in writing to the supervisor, stating the reason for the request and the length of time for which the change is desired. Consideration will be given on a case-by-case basis according to the merits of such requests; and wherever practical, deserving applicants will be temporarily transferred for a specific period as follows:

Any vacancy in the employee’s classification on the desired shift/location. If no vacancy exists, the senior applicant for the shift to which the hardship employee is currently assigned will be offered the opportunity to exchange schedules for the duration of the hardship.  If there are no applicants, another employee may voluntarily exchange schedules with the hardship applicant for the requested length of time, if the exchange is practicable under all circumstances. In the event there are no volunteers to exchange schedules with the hardship applicant, the supervisor, a Labor Relations Consultant and the Union Business Manager will discuss the merits of such requests for possible resolution.

Vacation: The Company recognizes its obligation in accordance with Article 11.1 of the CBA relative to vacation scheduling.  However, if an individual is granted a new shift/location as a result of the April/October application process, his/her previously approved vacation will be subject to availability on the newly assigned shift/location.  Management will endeavor to accommodate the original vacation request(s) whenever possible, but the employee assumes the risk that their original vacation dates may not be available.

6.19 FLEX SCHEDULING

With prior approval of immediate supervision, regular employees will be allowed flexibility in the starting and quitting times of their scheduled eight (8), ten (10), twelve (12) hour shifts.  The purpose of the program is to enable employees to attend to family, medical, community and other needs which may occasionally arise by reporting to work later than scheduled or leaving work earlier than scheduled, and to make up the scheduled time not worked.

65

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

The program will be administered subject to service requirements of the Company and the following conditions:

§   An employee who works less than a regular scheduled shift will be paid only for the time actually worked on that shift.

§   Make-up hours must be worked within the workweek in which a flex schedule is granted.  Also, make-up hours shall not be denied once the flextime has been taken off.

§   Corresponding make-up hours shall be reflected as such in the employee’s time card.

§   No more than sixteen (16) flex hours will be allowed in any rolling thirty (30) day period.

§   Make-up hours available but not worked within the workweek will be treated as an unpaid absence and shall be subject to the attendance policy.

§   Employees may use vacation time as make-up time with supervisory approval.

§   Make-up hours will be paid at straight time regardless of the shift or day on which they are worked.

No grievance will be filed asserting that the program violates any provision of the Labor Agreement, which may conflict or be inconsistent with the program.

6.22 ELIGIBILITY TO APPLY FOR VACANCIES:  Employees who are hired in a position in the Clerical Collective Bargaining Agreement shall not be permitted to apply for other positions for six (6) months after their hire date.  However, if there are no internal applicants for a position, the Company and Union agree to accept applications from Clerical employees who were hired less than six (6) months prior to the job posting before considering external applicants.  If an employee’s probationary period is extended, they will not be able to bid until probationary period is completed.

6.23 STARTING WAGE RATES FOR EXPERIENCED CSR’S: Employees who are hired as Customer Service Representatives (CSR)’s in the Call Center or who are promoted or transferred to CSR positions in the Call Center who have at least two (2) years of continuous experience working in a call center with the same Company, shall be granted one year of credit and paid at the third (3) step of the wage progression for CSR. Customer Service Representatives in the Call Center who do not have at least two (2) years of continuous experience working in a call center will be paid at the first (1) step of the wage progression for CSR. Employee must provide proof of experience prior to interview.

66

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

CLERICAL

ALTERNATIVE SHIFT SCHEDULES

Four-Ten Hour Shift in Customer Service

WORKING HOURS AND RATES OF PAY:

Workday: Ten (10) hours in any one (1) day shall constitute the workday.

Work Week: Four (4) workdays, regularly scheduled between the hours of 12:01 a.m., Monday, and 12:00 midnight, Sunday, shall constitute the basic work week. The work week of alternative-shift employees shall be from Monday through Sunday and reflect a schedule of forty (40) hours of straight time work.

Days Off:In regards to four-ten shifts there will be a minimum of two consecutive days off during the work week.  The third day off may be scheduled non-consecutive.

Shift Designations: The following designations shall apply:

o   FIRST SHIFT: All ten (10) hour shift periods regularly scheduled to begin at 5:00 am, or thereafter but before 12:00 noon shall be designated as first shifts.

o   SECOND SHIFT: All ten (10) hour shift periods regularly scheduled to begin at 12:00 noon or thereafter but before 8:00 pm, shall be designated as second shifts.

o   THIRD SHIFT: All ten (10) hour shift periods regularly scheduled to begin at 8:00 pm, or thereafter but before 12:01 am, shall be designated as third shifts.

Lunch Periods:  refer to Article 6.3 General.

Overtime:  In computing overtime, intermission taken out for meals and any holiday or vacation paid in that pay period will be considered as time worked.

Time And A Half:  Except as otherwise provided in this Article, the following situations shall require payment at one and one-half (1 1/2) time the regular established wage rate:

■   Time worked in excess of ten (10) hours per day.

■   Time worked in excess of any four (4) scheduled workdays in that workweek except when in conjunction to Flex Scheduling per Article 6.19.

■   Work scheduled in the three (3) hours immediately preceding the normal starting time.

■   Employees who are scheduled to work on an observed holiday.

■   Employees who are scheduled for overtime and such is canceled per Article 6.9 (Required Notice For Overtime)

Double Time:  Except as otherwise provided in this Article, the following situations shall require payment at two (2) times the regular established wage rate:

■   Employees who work on the third regular day off.

Rest Time:  Employees who are required to work overtime within the ten (10) hour period immediately preceding their scheduled starting time on a regular work day, shall be entitled to time off with straight time pay equal to time worked during this time frame. This is not applicable to a call out or scheduled overtime of three (3) hours or less immediately proceeding the employee's normal starting time.

Meals: refer to Article 6.15 General.

Holidays: It is understood that Employees may, at their discretion, use two (2) hours of vacation time, flex time or two (2) hours of unpaid time on holidays to ensure a full eighty (80) hour pay period.  When a holiday falls on an employee’s regularly scheduled day off the company will endeavor to schedule the day off as the last scheduled non-overtime work day

67

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

immediately preceding the holiday or the non-overtime work day immediately following the holiday shall be observed as the holiday for the purpose of this Article.  However, the holiday could be scheduled within the pay period to minimize any operational issues.  Notice of the date that the holiday will be observed shall be posted within the work group a minimum of one week prior to the holiday itself.

68

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

EXHIBIT I

 CLERICAL

JOB CLASSIFICATION DESCRIPTIONS

                                                                                                                                  (Alphabetical)

FIELD SERVICE REPRESENTATIVE (5161)

Performs various assignments relating to field Customer Service and Metering activities, including the duties of Meter Reader.  Individual assignments are based on requests from the Customer Service department and customer service orders which include, but are not limited to, turn-ons and turn-offs, check readings, and miscellaneous testing of both customer-owned and Company-owned electrical equipment.  May enter substations, co-generation facilities and LGS facilities to probe and read time-of–use meters.  The employee will be required to operate a vehicle for the Company.  Performs other related work, including semi-skilled work in other meter services areas, for which the employee is capable and qualified to safely perform as assigned. FSR’s required to perform meter reader duties will be selected using inverse seniority for work during the normal shift.

SENIOR CUSTOMER SERVICE REPRESENTATIVE (5174)

Performs very sophisticated clerical tasks, which require extensive decision-making authority, and independent judgment.  Employees in the classification work in the following areas:

■   Head Cashier

■   Service Dispatching

■   Districts

■   LGS Billing

CUSTOMER SERVICE REPRESENTATIVE (5374FT/5376 PT)

Performs varying degrees of clerical functions, from intermediate to fairly sophisticated, which require typing skills and the use of office equipment, personal computers, and business software systems.  Customer interaction requires extensive use of customer service skills and a significant degree of decision-making authority.  Employees in the classification work in the following areas:

■   Call Center

■   Commercial Office Support

■   Customer and Field Operations

■   Customer Credit and Billing

■   PBX

■   Material Management

REVENUE PROTECTION INVESTIGATOR (5162)

Employee performs specialized assignments relating to current diversion and meter tampering. The employee will also be required to perform technical investigations with established procedures on customer-owned and Company-owned equipment; does not include instrument metering. The employee will be required to work closely with low voltage electricity, while investigating, with various testing equipment. Will be familiar with associated office equipment, and work with and have knowledge of other department's functions, relating to detection and billing. Will drive a Company vehicle and be assigned to the Revenue Protection Department. Performs other related work, including semi-skilled work in other areas, for which the employee is capable and qualified to safely perform as assigned.

LEAD

In the absence of appropriate supervision or when directed, leads, assists, and works with other departmental personnel to ensure the efficient operation of related activities.  May be required to develop schedules, direct work assignments, prepare job related reports, complete other administrative duties, function in a customer or field service capacity, and perform other work as needed.

LEAD, SUPPORT SERVICES (5371)

In the absence of appropriate supervision or when directed, the lead will assist and work with other departmental personnel to ensure the efficient operation of related activities of the internal and external Mail Distribution services, Information and Record Management, Copy Center and the Corporate Switchboard.  May be required to develop schedules, direct work assignments, prepare job related

69

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

reports, training, complete other administrative duties, function in a customer or field service capacity and perform other work as needed.

MAIL & SUPPLY TECHNICIAN (5416)

Performs a variety of support service functions, which may include assisting departments to input orders, verifying electronic supply orders on ERP system and other electronic ordering systems, maintaining necessary stock, filing and duties related to inventory management, communicates with internal customers and occasional interface with external customers and operates office equipment, including but not limited to mail processing, switchboard and printing/duplicating equipment. Responsible for maintaining machines in clean operating condition and may perform some routine maintenance and adjustments. May be assigned other related duties as necessary such as maintaining a safe and clean work area, driving Company vehicles, pickups,  delivery and lifting (as outline in Union handbook lifting requirements) will include the use of necessary  tools to assist in performing duties as assigned. Require experience in office environment and basic operation of computer systems.

METER READER (5412 FT/5415 PT)

Employee reads meters, including probing time-of-use survey and LGS commercial meters, in Company service areas, and records readings, comments, and miscellaneous information on proper forms and into handhelds.  Indicates abnormal or unusual conditions relative to meters and facilities.  May be required to operate vehicle for Company. Performs other related work, including preparing reports, for which the employee is capable and qualified to safely perform as assigned. The ratio for part-time Meter Readers will be five (5) full-time employees for every one (1) part-time employee.

REPROGRAPHIC TECHNICIAN (5270)

Employee will be responsible for the production of in-plant printed and copied material. Including but not limited to: offset printing, bindery, and finishing equipment as well as networked and non-networked production copying equipment. Will be responsible for maintaining/keeping department and equipment in clean and safe operating condition. Provide general administrative support and may be assigned other duties as assigned. This position supports Supply Services.

TRAINER FIELD OPERATIONS (5182)

Assists management and the Customer Service Training & Performance Department by identifying training needs, participating in job/task analyses, providing small group and/or one-on-one and just-in-time training support, and actively participating in planning the Trainer In-Service Program.  Responsible for performing regular Field Service, limited Customer Service functions and working with training staff on training goals and self-development in training capacity.  This position will support the Field Operations Department including, but not limited to: Meter Reading, Field Services and Meter Operations.  May be required to work various shifts and at various locations.

TRAINER CUSTOMER CARE (5183)

Assists management and the Customer Service Training & Performance Department by identifying training needs, participating in job/task analyses, providing small group and/or one-on-one and just-in-time training support, and actively participating in planning the Trainer In-Service Program.  Responsible for performing regular Customer Service functions and working with training staff on training goals and self-development in training capacity.  This position will support the Customer Service Department including, but not limited to: Call Center Operations, Credit & Collections, Billing and the commercial offices.  May be required to work various shifts and at various locations.

70

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

CLERICAL – WAGES
Job Code	Job Title	Step	09/01/11 1.5%	1st Pay Period After 02/01/12 1.0%
5061	Lead Field Service Rep	1	28.27	28.55
5161	Field Service Rep	1	22.30	22.52
	2nd Six Months	2	23.69	23.93
	3rd Six Months	3	25.77	26.03
5162	Revenue Protection Investigator	1	25.93	26.19
	2nd Six Months	2	27.06	27.33
	3rd Six Months	3	28.09	28.37
	4th Six Months	4	29.14	29.43
5174	Senior Customer Service Rep	1	21.41	21.62
	2nd Six Months	2	22.37	22.59
	3rd Six Months	3	23.38	23.61
	4th Six Months	4	24.43	24.67
	5th Six Months	5	25.68	25.94
5175	Lead Customer Service Rep	1	25.35	25.60
5177	Lead Field Srvc Investigator	1	32.08	32.40
5182	Trainer METER	1	28.27	28.55
5183	Trainer TSO	1	28.27	28.55
5270	Reprographic Tech	1	21.12	21.33
	2nd Six Months	2	21.88	22.10
	3rd Six Months	3	22.65	22.88
	4th Six Months	4	23.39	23.62
	5th Six Months	5	24.15	24.39
5274	Customer Service Rep	1	15.12	15.27
5273 p/t	2nd Six Months	2	16.47	16.63
	3rd Six Months	3	17.78	17.96
	4th Six Months	4	19.13	19.32
	5th Six Months	5	20.48	20.68
5371	Lead Support Services	1	26.56	26.83
5411	Lead Meter Reader	1	26.69	26.96

71

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

CLERICAL – WAGES
Job Code	Job Title	Step	09/01/11 1.5%	1st Pay Period After 02/01/12 1.0%
5412	Meter Reader	1	16.28	16.44
5415 p/t	1st Three Months	2	16.92	17.09
	2nd Three Months	3	17.48	17.65
	2nd Six Months	4	18.06	18.24
	3rd Six Months	5	18.65	18.84
	4th Six Months	6	19.23	19.42
	5th Six Months	7	19.82	20.02
	6th Six Months	8	20.42	20.62
	7th Six Months	9	20.97	21.18
5416	Technician, Mail & Supply	1	13.58	13.72
	2nd Six Months	2	14.78	14.93
	3rd Six Months	3	16.00	16.16
	4th Six Months	4	17.50	17.68
	5th Six Months	5	19.27	19.46

72

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

T & D

ARTICLE NO. 4

Union Activity

4.3             T & D CONTRACTING WORK:

In case the Company should contract any type of work customarily performed by Bargaining Unit employees, the Company shall, before awarding such contract, advise the contractor that the work is to be done under not less than the terms and conditions pertaining to hours and wages set forth in the Collective Bargaining Agreement. Upon award of such contract, the Company shall notify the Union in writing within thirty (30) calendar days of any and all contracts awarded of such contractor and the nature of the work being performed. For all work that is contracted out, there shall be a match of man for man for all Bargaining Unit Classifications affected for all hours worked by such contractor. The Company will not contract any of its construction and maintenance work while having available competent employees to do such work. In the event the Company has employees on layoff with recall rights, the Company will not establish contracts for work that is customarily performed by such Bargaining Unit employees unless affected employees are not qualified to perform the work (as defined in Article 5.4 LAYOFF PROVISIONS). If the Company has employees in layoff status who are qualified to perform work, which the Company intends to contract, the Company may recall these employees for the term of the contracted work without creating the liability for an additional severance in accordance with Article 5 (STATUS OF EMPLOYEES) of this Agreement. The man for man match shall apply for all work except for construction of new transmission lines.

4.4             CONTRACTING WORK – MAPPING ONLY:

In case the Company should contract any type of work customarily performed by Bargaining Unit employees, the Company shall, before awarding such contract, advise the contractor that the work is to be done under not less than the terms and conditions pertaining to hours and wages set forth in the Collective Bargaining Agreement. Upon award of such contract, the Company shall notify the Union in writing within thirty (30) calendar days of any and all contracts awarded of such contractor and the nature of the work being performed. Due to the nature of the work, company reserves the right to retain and not exceed 25% of their projects as contractors. In the event the Company has employees on layoff with recall rights, the Company will not establish contracts for work that is customarily performed by such Bargaining Unit employees unless affected employees are not qualified to perform the work (as defined in Article 5.4 LAYOFF PROVISIONS).

4.5 CONTRACTING WORK – UDC & SENIOR PROJECT COORDINATORS ONLY:

In case the Company should contract any type of work customarily performed by Bargaining Unit employees, the Company shall, before awarding such contract, advise the contractor that the work is to be done under not less than the terms and conditions pertaining to hours and wages set forth in the Collective Bargaining Agreement. Upon award of such contract, the Company shall notify the Union in writing within thirty (30) calendar days of any and all contracts awarded of such contractor and the nature of the work being performed. Due to the nature of the work, company reserves the right to retain and not exceed 25% of their projects as contractors. In the event the Company has employees on layoff with recall rights, the Company will not establish contracts for work that is customarily performed by such Bargaining Unit employees unless affected employees are not qualified to perform the work (as defined in Article 5.4 LAYOFF PROVISIONS).

4.6 CONTRACTING WORK – FACILITIES ONLY

Both parties reserve the right to sit down and discuss all construction projects prior to the start of such project.

73

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

NEW CONSTRUCTION AND SYSTEM UPGRADES: FACILITIES ONLY:

The company will assign Bargaining Unit Quality Assurance person to each new construction and system upgrade project.  If the “Q.A.” person assigned feels the work is beyond his/her scope, the appropriate craft person shall be assigned.  The Q.A. person will help to insure the contractor is performing work up to our standards, as well as be the contact person for equipment maintenance in the future.  The Q.A. person will periodically monitor the progress as well as perform his/her normal duties.  The Q.A. person for Facilities will be a Tech III.

74

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

T & D

ARTICLE NO. 6

Working Hours and Rates of Pay

6.1 DEFINITIONS:

SHIFT:  Hours of work.

SCHEDULE:  Days and hours of work.

WORK DAY: Eight (8) hours in any one (1) day shall constitute the work day; however the Company and Union may enter into Agreements which establish alternative work schedules involving work days which have more than eight hours.

WORK WEEK: Five (5) consecutive work days, regularly scheduled between the hours of 12:01am, Monday, and 12:00 midnight, Sunday, shall constitute the basic work week.  The basic workweek of regular day-shift employees shall be from Monday through Friday and reflect a schedule of forty (40) hours of straight-time work.

REGULAR DAYS OFF: Days off shall be consecutive, however, they may not be within the basic workweek.

REGULAR DAY-SHIFT EMPLOYEES: Regular day shift employees are those employees who are assigned to shifts, which are established on a Monday through Friday schedule and work a shift, which begins between the hours of 7:00 am and 11:59 am.  When mutually agreed to by the Union and Company, the day shift starting time may be scheduled as early as 6:00am to take advantage of daylight hours. Only Fleet Services and Clerk Dispatchers starting time may be scheduled as early as 5:30am.

SEVEN DAY COVERAGE: A schedule of fixed or rotating shifts that cover seven (7) days per week, twenty-four (24) hours per day.

SHIFT EMPLOYEES: Shift employees are all employees not defined as regular day-shift employees.  This includes employees assigned to fixed shifts and seven (7) day coverage.

SHIFT DESIGNATIONS: No shift periods shall start between the hours of 12:01 am and 5:59 am, unless mutually agreed to by memorandum of understanding between the Company and the Union.  The follow designations shall apply:

FIRST SHIFT: All eight (8) hour shift periods regularly scheduled to begin at 6:00 a.m., or thereafter but before 12:00 noon shall be designated as first shifts.

SECOND SHIFT: All eight (8) hour shift periods regularly scheduled to begin at 12:00 noon or thereafter but before 8:00 p.m., shall be designated as second shifts.

THIRD SHIFT: All eight (8) hour shift periods regularly scheduled to begin at 8:00 p.m., or thereafter but before 12:01a.m., shall be designated as third shifts.

SHIFT DIFFERENTIAL: An incremental increase for working on a second or third shift.

SHIFT PREMIUM: An incremental increase for all hours worked outside of the employee's previous schedule for the first five (5) working days of a newly established permanent, temporary or emergency schedule.

SHORT CHANGE: A transfer from one established schedule to another with only one shift off between schedules.

75

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

COMPANY HEADQUARTERS: Any headquarters established for the purpose of engaging in work covered by this Agreement when such work will continue for an indeterminate period of time.

6.4 OVERTIME: In computing overtime, intermission taken out for meals served other than on the job shall be deducted, and any holiday or vacation paid in that pay period will be considered as time worked.

NO PYRAMIDING OF OVERTIME:  The employee will only be entitled to the highest single premium rate applicable to the work assigned by the CBA.  There will be no pyramiding of overtime.

TIME AND A HALF: Except as otherwise provided in this Article, the following situations shall require payment at one and one-half (1 1/2) times the regular established wage rate:

• Time worked in excess of eight (8) hours per day.

• Time worked in excess of any five (5) scheduled workdays in that workweek.

• Work scheduled in the three (3) hours immediately preceding the normal starting time.

• Employees scheduled to work on an observed holiday.

• Employees on seven (7) day coverage who are scheduled or called out for overtime except as defined in "Double Time."

• Employees who are scheduled for overtime and such is canceled per Article 6.9 (REQUIRED NOTICE FOR OVERTIME).

DOUBLE TIME: Except as otherwise provided in this Article, the following situations shall require payment at two (2) times the regular established wage rate:

• Employees, other than those assigned to seven (7) day coverage, (excluding line troubleman), who are scheduled to work within the first five (5) hours of the eight (8) hour period immediately preceding the normal starting time regardless of the day of the week.

• Employees who work on the second day of a two-day off period, or on the second or fourth days off of a four days off period with an overtime minimum as provided in Article 6.7 (CALL-OUTS).

DOUBLE TIME AND A HALF: Except as otherwise provided in this Article, the following situations shall require payment at two and one-half (2 1/2) times the regular established wage rate:

• For all time worked in excess of sixteen (16) consecutive hours.

BREAK PERIOD: Employees entitled to pay at this rate will continue at this rate until they have been released for a period of at least six (6) continuous hours.  Any break of six (6) hours will be considered an interruption of continuous work time.  It is understood that any employee may be returned to work exactly six (6) hours from their most recent release, satisfying the required break.  It is also understood that any employee released for such a break may be called back to work before six (6) hours have elapsed.

MEAL PERIODS:Meal periods while working overtime will not be considered as part of the six (6) hour break and will not be considered time worked, unless employees are directed to work through their meal period.  Employee's unpaid meal period which occurs during regular work hours will be included in the computation of the six (6) hour break, when this break is

76

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

calculated from the end of the employee's last regular shift.  Accordingly, an employee may be called out five and one-half (5 1/2) hours from the end of their last regular shift without creating a requirement for this rate.

STRAIGHT TIME PAY: Employees sent home for a six (6) hour break will not lose any straight time pay for normally scheduled hours, as a result of such a break.

Example

Employees assigned to a 7:00 am to 3:30 pm shift and released two (2) hours early so they may

have a six (6) hour break before a scheduled outage would be paid for the two (2) hours

at the straight time rate and this would satisfy the six (6) hour break.

Employees must use any rest time pay accumulated as a result of an overtime assignment before these provisions would apply. If an employee's accumulated rest time does not cover the entire six (6) hour break, the employee will receive straight time pay for any regularly scheduled hours not worked due to this break.

6.5 OVERTIME EQUALIZATION: (Does not apply to UDC or Mapping classifications) The Company will endeavor to distribute overtime work as evenly as possible among those employees qualified to perform such work. For the purpose of distributing overtime, the Company will maintain and post overtime lists in each sub-department indicating time offered and time worked. Each department will create policies and procedures (BY LOCATION, SHIFT – as defined by Article 6.1 AND CLASSIFICATION), for overtime equalization through labor/management meetings.

6.7 CALL-OUTS:

TWO-HOUR MINIMUM:  Employees called out for overtime duty shall receive at least two (2) hours pay.  Reasonable travel time (defined below) to and from home will be considered as time worked for the purpose of satisfying the two (2) hour minimum, and will be paid at the appropriate overtime rate.

Example #1

Employees called out who work two (2) hours and travel one (1) hour (round trip) will be paid

for three (3) hours.

Example #2

Employees called out who work four (4) hours and travel one (1) hour (round trip) will be

paid for five (5) hours.

Example #3

Employees called out who work one (1) hour and travel one (1) hour (round trip) will be paid

for two (2) hours.

Example #4

Employees called out who work fifteen (15) minutes and travel one (1) hour (round trip) will

be paid for two (2) hours.

Example #5

Employees called out who work into their regular shift shall be paid the appropriate overtime

premium for at least two (2) hours, which includes travel time to work only.  This does not

change the normal starting time for the purpose of extending the shift.

MULTIPLE CALL-OUTS: Employees called-out more than once in the twenty-four (24) hour period from midnight one day to midnight the following day shall be paid at least the two (2) hour minimum mentioned above for the first call. For subsequent calls, employees shall be paid for a one (1) hour minimum with the same travel time considerations mentioned above.

 

77

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

For the purpose of this section, concurrent calls or successive calls without a break in work time shall be considered as a single call.

TRAVEL TIME: Employees are entitled to travel time according to the following chart:

Locations	Las Vegas Valley	Reid Gardner	Laughlin
Las Vegas Valley	.5 hour	1 hour	2 hours
Moapa Valley	1 hour	.5 hour	3 hours
Boulder City	.75 hour	1.5 hours	1.5 hours
St. George/Alamo	2 hours	1.5 hours	4 hours
Mesquite	1.5 hours	.75 hour	3.5 hours
Laughlin	2 hours	3 hours	0
Henderson	.75 hour	1.5 hours	1 hour

6.9 REQUIRED NOTICE FOR OVERTIME:

SCHEDULED OVERTIME: In scheduling overtime work, a minimum of fourteen (14) hours notice is required, prior to the start of any overtime for a particular day, and before leaving the work site on a regular work day. Without this notice, such work will be considered as a call-out. It is understood that overtime, when worked as an extension of a regular shift, does not require such notification.

Example:

An employee assigned to a 7:00 am to 3:30 pm shift and held over for overtime and is

notified to work the next day  (his/her day off) at 7:00 am. If notification is given in the first two

(2) hours of held over overtime, this overtime is considered scheduled.

CANCELING OVERTIME: A minimum of twelve (12) hours notice is required on canceling pre-scheduled overtime. When customer arrangements are involved, the Company must provide twelve (12) hours notice prior to the employee's next normal starting time. When such notice of cancellation of pre-scheduled overtime work is not given in accordance with the above, employees involved will be paid for two (2) hours at established overtime rates if they report and are retained for work. When such notice of cancellation is not given in accordance with the above, but employees are later notified of work cancellation, they will be paid for two (2) hours at established overtime rates. If they report and are not retained for work, they shall receive pay for two (2) hours at established overtime rates

6.18 MUTUAL ASSISTANCE: The Company and the Union recognize the importance of assisting communities whose citizens may be in severe distress due to outages caused by wild fires, storms, etc.  In order to facilitate being able to send NV Energy’s employees while not hindering the day-to-day operations of the business; it is agreed that: 1) the Company will select those employees whose qualifications will be most valuable in assisting the community that is suffering due to outages/adverse conditions.  Selection of qualified employees will be made according to the (i) “on call crew” at the time the assignment is made, and (ii) the low equivalent overtime list at the time the assignment is made; however, 2) any Employee in discipline for misconduct or whose assignment would disrupt an ongoing NVE major project will not be eligible for assignment under this Article.

Any employees selected by the Company to assist the suffering community must own the requisite gear/clothing for giving assistance in the specific climate where the outage has

78

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

occurred.  Any employee without the proper gear must either turn down the selection or be responsible for purchasing proper gear/clothing at the employee’s own expense.

Any employees selected to assist a community in distress will work under and be subject only to the NV Energy/IBEW Local 396 Collective Bargaining Agreement.

 

79

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

T & D

ARTICLE NO. 16

Working Rules

16.1 SAFETY GEAR: Rubber gloves, hose, hoods and blankets may be used to make as safe as possible any work performed on any equipment having conductors energized in excess of 750 volts, in addition, hot line tools may be used where applicable. The safety precautions taken by the crew are the direct responsibility of the foreman in charge.  The Occupational Safety and Health Standards as contained in sub-part "v" of the Occupational Safety and Health Act (OSHA) shall be considered minimum standards for work performed on power transmission and distribution equipment.

16.2 TWO MAN CREW: A two (2) man crew shall be made up of two (2) Journeymen Lineman or one Journeyman Lineman and an Apprentice Lineman that is qualified to complete the particular work assigned. In all cases the company will endeavor to use two (2) Journeymen lineman, and designate one of them as the employee in charge to direct all the work.

16.3 T&D ENERGIZED WORK: All lines energized at 4 kv, phase to phase, or above shall be handled in accordance with 1910.269 subpart “R” of the Occupational Safety and Health Act (OSHA). When working on energized lines / electrical apparatus with live line tools, two (2) qualified and authorized employees shall be on the pole to do the work. They shall be at all times under the observation of a foreman who shall have no other duties at the time the work is being performed. Foreman shall use their judgment in and be responsible for the proper placing of their employees (ie, Foreman may delegate the observation duties to a qualified Journeyman Lineman when necessary) As an exception to the rule, one (1) such employee may be allowed to clean insulators in un-crowded conditions, do hot meggering, make current and voltage test, connect or remove the hot taps from the fuse holders to the line, provided the fuses are removed and adequate clearance can be maintained or emergency repairs by troubleman to the extent necessary to safeguard the general public. No employee shall be assigned to hot work on two hundred thirty thousand (230kv) or on higher voltages unless that employee has received training on such voltages.

16.5 FRAMING AND POLE CONSTRUCTION: All framing and erecting of poles or towers in the field shall be done by the line crew. All framing in any pole yard shall be done by a Journeyman lineman with the ratio of assisting apprentices and/or groundmen no greater than that in the majority of line crews on the system.

16.8 TEMPORARY LEAD LINEMAN: In the temporary absence of a regular Lead Lineman, when there is three (3) or more employees on a crew, one of those employees shall be paid at the Lead Lineman’s rate of pay for all hours worked. The employee chosen to be the lead will be responsible for all duties within the Lead Lineman job description; however this language is not intended to conflict with (Article 7.3 Staffing Vacancies).

80

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

EXHIBIT I

T & D

JOB CLASSIFICATION DESCRIPTIONS

 (Alphabetical)

APPRENTICE COMMUNICATIONS ELECTRICIAN (7024)

Assists the communications electrician while in training of Journeyman; installs and maintains the sophisticated voice, data and video communications equipment while working under the direct supervision of Journeyman Communications Electrician. May be required to perform other activities as assigned.

APPRENTICE EQUIPMENT MECHANIC  7013)

Assists the equipment mechanic while undergoing training for the Journeyman level. Does such work as tuning motors, adjusting valves and ignitions, cleaning fuel systems and radiators’, adjusting clutches, brakes and carburetors, tests compression of oil and fuel pressure.

APPRENTICE LINEMAN (7020)

Assists in all work performed by a lineman while engaged in learning lineman work under the direct observation of a Journeyman lineman; climbs poles in the installation of cross arms, guy wires, insulators, pins and wires, etc., splices transformer leads and solders and tapes connections and may be required to perform other duties as assigned.

APPRENTICE METERING ELECTRICIAN (7022)

Assists in all the work performed by the Meterman while undergoing training for the Journeyman level; tests meters, programs meters, completes all appropriate paperwork, sets all meters, wires panels, wires primary, secondary, substation, generation, and transmission metering circuits all under the supervision of a Journeyman Meterman, and may be required to perform other duties as assigned.

APPRENTICE SUBSTATION ELECTRICIAN (7021)

Assists the substation electrician while in training for Journeyman; assists the Journeyman in his work in the construction, maintenance and operations of substations and switchyards; cleans, makes tests and does minor repair of all substation equipment, fixtures, wiring, and may be required to perform other duties as assigned.

CIRCUIT INSPECTOR (6111)

Makes periodic, routine and emergency inspections and repairs of all electrical distribution facilities, and property owned by the Company, including rights-of-way, and overhead line and underground facilities; identifies system encroachments, and deteriorating and defective equipment; and prepares related reports necessary to perform required maintenance and repairs. May be required to operate sonic, or other test equipment, perform incidental tasks, minor repairs that can safely be completed by a Journeyman, and related work as required. Must be thoroughly familiar with distribution construction standards and practices, and be able to recognize system deficiencies on sight.

CLERK DISPATCHER (5144)

Responsible for Distribution Construction and Maintenance activities related to analyzing construction and maintenance work orders to determine a plan of optimum work method, crew size, equipment and man hours. Coordinates maintenance projects for Transmission and Distribution. Schedules work processes for the coordination, construction and maintenance of underground and overhead distribution projects. Responsible for customer contact on all projects while under construction and maintenance, Receives and logs all work orders. Prepares related material requests and ensures that material is available and staged. Makes arrangements to have holes dug and poles delivered before dispatching crews to jobs. Dispatches crew and keeps log on their location in order to dispatch them efficiently to their next job. Sets up scheduled outages when required and conducts field check jobs. Prepares daily and monthly reports and work orders and closes out all jobs. Answers radio and telephones and does general office clerical work as required. Performs other related work for which employee is capable and qualified to perform as assigned.

 

81

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

CLERK DRIVER (6188)

Drives truck; operates power winch; maintains truck and equipment in orderly manner; does field clerical work, such as maintaining records of materials used, materials needed the following days, preparation of time cards and any other records as directed by the foreman; works as a groundman if so required by the foreman.

COMMUNICATIONS ELECTRICIAN I (6197)

With supervision and oversight be capable of diagnosing the causes of poor performance or non-operation of radio or communication equipment. Performs installation, field testing and maintenance of communications systems, telephone switchboards and other terminal equipment, supervisory, microwave, multiplex, radio, 950 MHz data radios, "T" carrier, fiber optic, hardware, and multiplex tone equipment, scada/ems computer, rtu, and all associated hardware, fiber optic cable splicing, remote signal and remote control equipment, load frequency control and telemetering equipment, and any new technology related to Telecom that the company decides to use. This position is not to be considered a permanent position but is a training position for the Communication Electrician II position. The Communication Electrician I shall qualify for the Communication Electrician II position by demonstrating, on-the-job, that he or she has acquired the necessary skills to qualify and then pass a written proficiency exam.  Must have a valid FCC general class radiotelephone operator's license, or valid NABER or NARTE certification.  May be required to perform any of the duties assigned to the electrician classification.  If the employee has successfully completed Company’s Communications apprenticeship program, this position can be bypassed and the employee can move directly into the Communication Electrician II classification.

COMMUNICATIONS ELECTRICIAN II (6108)

With almost no supervision and oversight be capable of working independently to diagnoses the causes of poor performance or non-operation of radio or communication equipment. Performs installation, field testing and maintenance of communications systems, telephone switchboards and other terminal equipment, supervisory, microwave, multiplex, radio, 950 MHz data radios, "T" carrier, fiber optic, hardware, and multiplex tone equipment, scada/ems computer, rtu, and all associated hardware, fiber optic cable splicing, remote signal and remote control equipment, load frequency control and telemetering equipment, and any new technology related to Telecom that the company decides to use. Must have a valid FCC general class radiotelephone operator's license, or valid NABER or NARTE certification. Must be a Journeyman communications electrician with at least two years of experience in that classification or successfully completed the Company’s Communication apprenticeship program. May be required to perform any of the duties assigned to the Electrician classification.

COMMUNCIATIONS GROUNDMAN (6185)

Performs semi-skilled work functions and tasks when necessary, as assigned by supervisor, communications lead, or Journeyman or apprentice supplied with tools, materials, and supplies while assisting with specific jobs. Work assignments will provide training to enhance job knowledge and skills for progression in career path towards electrical apprenticeship. At no time, however, shall a groundman be allowed to work on energized equipment or liens. Responsible for keeping job sites clean and may be required to perform such other duties as assigned.

COMPANY WIDE WELDER (6130)

Performs all types of high pressure, gas and electrical welding. Will have fabrication skills (ie. gas, electric and mechanical cutting) Must be capable of welding, brazing and/or soldering carbon, stainless, alloy steels, aluminum and bronze. Will be required to work intermittently with T&D personnel, on, below and above ground, if necessary. Will perform any and all tasks for which they are properly trained and can competently and safely perform It is never the intent for a welder to perform work that is traditionally done by Journeyman.

CREW CHIEF (7095)

Directs the work and activities of the Survey Crew in the performance of measurements upon the land of features and fixtures of Company owned land and land rights, construction layout and staking of improvements and facilities, and other survey related activities in support of Company objectives.

82

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Maintains and operates all survey and survey related equipment. Reviews plans for accuracy, performs research, calculations and other field checks to insure correctness, maintains data collector files, and oversees survey crew to make sure correct survey procedures and safety requirements are met. Possesses fundamental knowledge of Land Survey principles and practices and actively pursues performance excellence. The Crew Chief shall be responsible for the survey crews activities in the performance of their duties. Performs such other duties as may be assigned.

An employee who holds the position of Crew Chief will automatically progress to the position of Surveyor (3178) once they obtain a Professional Land Surveyor’s License and once they provide the Company with documentation of obtaining the license.  Should the license expire or be revoked, the employee will return to the classification and rate of pay of Crew Chief.  The Company may require a Surveyor to provide documentation of a current Professional Land Surveyor’s license on an annual basis.

DESIGN FACILITATOR (7097)

Reviews construction designs for accuracy and appropriate specifications and standards. Assists design team in the training and development of constructible designs. Researches field equipment and field conditions for compatibility to design. Makes recommendations, decisions and/or changes that will effect the workability, reliability, and safety of the installation and maintenance of equipment. Employee can observe and verify proper installation of facilities in accordance with company specification and standards. Has contact with company employees, customers and company contractors. Must be skilled to perform all types of work specific to the Journeyman Lineman classification. Employee will perform any and all tasks for which they are trained and can competently and safely perform. Performs related duties to help ensure job site and design readiness prior to construction.

ELECTRICAL INSPECTOR (6112)

Responsible for inspecting electrical installations performed by Company and contract personnel, Inspects electrical service requirements within residential subdivisions and/or commercial developments. Will perform electrical inspections and other duties beyond the main trench. Inspects installation and removal of appropriate distribution system. Observes and verified the proper installation of facilities in accordance with Company specifications and standards and performs material audits. Has direct contact with customers and Company contractors. Must be skilled to perform all types of work specific to the Journeyman lineman classification. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

EQUIPMENT MECHANIC (6150)

Performs skilled mechanical work in the maintenance and repair of motor vehicles of all types of motor vehicles, cranes, aerial devices and associated equipment; inspects passenger cars, trucks, pickups and other transportation equipment to determine needed repairs, makes such repairs as are possible in the Company shop, diagnoses motor and other equipment troubles and recommends sending them out or repairing them in-house. Maintains work and vehicle records as required by the Company. Performs allother work as assigned.

EQUIPMENT OPERATOR   (6166)

Operates digger machine in boring of holes for poles and anchors; gives directions for raising and setting of poles; raising of electrical equipment and racks; make minor repairs and adjustment to digger machines; operates other special equipment including jackhammer as required and drives truck or pickup in performance of duties.

FIELD INSPECTOR (6110)

Inspects installation and removal of appropriate systems. Observes and instructs in the proper installation of facilities in accordance with Company specifications and standards and performs material audits. Has direct contact with customers and Company contractors. Must be skilled to perform all types of work specific to the appropriate trade. May be required to operate test equipment, perform incidental tasks and minor repairs that can safely be completed by a Journeyman, and may be required to perform other duties as assigned.

 

83

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

FLEET MAINTENANCE TECHNICIAN (6151)

Will perform all vehicle and equipment classes for preventative maintenance work (to include PM’s-A,B & C). Will be required to maintain work, vehicle and equipment PM records. Will be required to obtain ASE certifications in PM class. Upon training, the Fleet Maintenance Technician will be required to check all vehicle safety items, and advise the Lead of the condition of the vehicle or the equipment. Will be required to transport all company vehicles to and from locations to perform PM work, which requires a CDL license. Will be required to perform any of the above tasks. May be required to assist with or perform work in a lower classification and other related work for which the employee is capable and qualified to perform as assigned.

FLEET UTILITY TECHNICIAN (6182)

Operates mobile tank truck for fueling fleet vehicles at various locations. Must be able to obtain a CDL with haz-mat and tanker endorsements. Performs all types of tire repairs including split rims. Changes all types of tires in-house and in the field. Inspects vehicles for tire repairs of replacements. Operates tow truck for pickup and delivery of disabled vehicles. Assists Equipment Mechanic with preventative maintenance of all types of motor vehicles, cranes, aerial devices and associated equipment. Maintains work and vehicle records as required by the Company. Performs other work as assigned.

HIGH BOOM OPERATOR (6177)

Operates live booms with a reach of more than sixty (60) feet above ground level; makes minor repairs and adjustments on boom and truck; responsible for driving and maintaining truck and boom in safe and orderly manner. Maintains records as required by the Company, works in lower classifications as assigned.

LEAD

In the absence of appropriate supervision and when directed, leads, assists, and works with other departmental personnel to ensure the efficient operation of related activities.  May be required to develop schedules, direct work assignments, prepare job related reports, complete other administrative duties, function in a Journeyman capacity, and perform other work as needed.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

LINE CLEARANCE INSPECTOR (6100)

Directs, assigns, and inspects all Company and contract tree trimming maintenance activities. Assists other department personnel to ensure efficient operation of related activities. May be required to develop schedules, direct work assignments, dispatch crews, prepare job related reports, train departmental personnel and perform tree-trimming activities. Has direct contact with customers and promotes good public relations. May also be required to perform Line Groundman responsibilities and other duties as assigned.

LINE GROUNDMAN (6136)

Assists a lineman in a crew in the laboring work involved in the setting up of overhead transmission lines and overhead and underground distribution lines; digs holes; clears rights-of-way; handles tools and materials; steadies poles as they are raised by winch and tamps dirt around the pole to hold it in place: passes work tools, equipment and material from ground to lineman on the poles; may be required to drive a truck; may be permitted to climb. A groundman shall be permitted to climb only in established training sites, which are not energized and may be required to perform other duties as assigned.

LINE PATROLMAN (6180)

Patrols overhead transmission and distribution lines by truck or helicopter. Will observe and report any damaged structures or equipment. Will re-fuse capacitor banks and will fill out and give trouble reports to the supervisor. Must be qualified to use specialized equipment for detecting radio and television interference. May be required to tighten hardware on NV Energy fixtures. Will be required to patrol and tong the static line on the 500kv line semi-annually with another Journeyman. May have to perform light maintenance such as replacing guy guards, switch handles and pull down guys. May be required to switch in remote line locations and substations, and other duties as assigned.

 

84

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

LINE TROUBLEMAN (6113)

Installs services and single phase self-contained meters up to two hundred (200) amps; replaces line and transformer fuses; changes transformer taps when necessary; is skilled in all types of transformer hook ups; does line work to restore customer service; provides limited service and assists customers in emergencies; has direct contact with customers and tries to build good public relations; makes out necessary reports on car/pole accidents and equipment failures; operates OCB’s and ACB’s and other station equipment in restoring outages and when necessary for line work; must take training period provided by the Company to become qualified on substation and field switching and to operate and check for minor troubles in all line and substation equipment; may work on shift basis.

JOURNEYMAN LINEMAN (6123)

Constructs high voltage power transmission and distribution overhead & underground lines; makes construction changes to existing lines; fittings and equipment; repairs power lines; services lines and line equipment; sets poles; installs cross arms, transformers, transformer racks, self contained single phase meters of 200 amps or less, and services of various types and sizes.

JOURNEYMAN METERING ELECTRICIAN (6124)

Tests electrical and physical characteristics and accuracy of electricity meters, instrument transformers, transducers, and other electrical devices in the circuit for measuring, monitoring, and analysis of electricity. Performs all tasks except meter reading on all instrument rated metering systems and on self-contained meters over 200 Amps or over 250 volts. Performs all initial installations of three (3) phase meters of any voltage. Assists in tie-line, station, and generation meter testing, installation, repairs, modifications, and verification.  Installs, maintains, and performs basic troubleshooting for communication interface with customer load management equipment; Installs, maintains, and removes portable equipment for measuring, monitoring, and analysis of electricity. Utilizes computer to upload/download data and company-developed equipment programs and to enter equipment parameters. Prepares written reports on field and shop activity as necessary. Equipment selection, metering system design, and equipment program development are not within the exclusive scope of this classification.

MAINTENANCE TECHNICIAN (7094)

Performs a variety of skilled work including operating equipment, insulating, painting, lubricating and carpentry.  Will be required to perform any of the above tasks if necessary.  May be required to assist or perform work in any lower classification. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MAINTENANCE UTILITY TECHNICIAN (7092)

Does unskilled work as necessary; keeps Journeyman or apprentice supplied with tools, materials, and supplies while assisting with a specific job; cleans working area and equipment.  Operates other special equipment including jackhammer as required and drives truck or pickup in performance of duties.  A maintenance utility technician shall not displace an apprentice or a Journeyman or generation technician. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MAPPING TECHNICIAN I (3103)

This entry-level position performs work under the close guidance and direction of a Mapping Technician II, Senior Mapping Technician, or the Supervisor.  This position checks and updates both CAD maps and database attribute files with Work Order/Project designs that range in complexity from simple to moderately complex.  The position checks Work Order/Project designs for accuracy, completeness, and adherence to mapping standards and notifies a designated Mapping Technician II, Senior Mapping Technician, or the Supervisor of any inconsistencies or discrepancies discovered in the designs.  This position updates the network model and landbase data with corrections provided from a designated Mapping Technician II, a Senior Mapping Technician, or the Supervisor.  The position transfers project design landbase information to the CAD maps and database attribute files when necessary.  This position maintains the customer-to-transformer link within the mapping system.  This position will learn the operation of the mapping software as well as how the mapping software interacts with AutoCAD.  

85

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Performs other related work for which the employee is capable and qualified to safely perform as assigned.

MAPPING TECHNICIAN II (3104)

This position performs work under the limited guidance of a Mapping Technician II, Senior Mapping Technician, or the Supervisor.  This position checks and updates both CAD maps and database attribute files with Work Order/Project designs that range in complexity from simple to highly complex.  The position checks Work Order/Project designs for accuracy, completeness and adherence to mapping standards, and notifies a designated Mapping Technician II, Senior Mapping Technician, or the Supervisor of any significant inconsistencies or discrepancies discovered in the designs.  This position will attempt to clarify or resolve problems with the designs by contacting the appropriate people responsible for the Work Order/Project.  This position updates the network model and landbase data with corrections provided from a designated Mapping Technician II, Senior Mapping Technician, or the Supervisor.  The position transfers project design landbase information to the CAD maps and database attribute files when necessary.  The position will correct any corrupted CAD maps including landbase files and connectivity maps when found.  The position maintains the customer-to-transformer link within the mapping system.  The position coordinates with other departments to ensure that project design and as-built information is provided to the department in accordance with the required mapping standards.  This position will update the Distribution Operations wallboard information when necessary.  This position fully understands the interaction of the mapping software and AutoCAD and will generate solutions to problems that are encountered with this interaction.  This position prepares mapping software problem logs.  The position may provide training and development to all department technicians.  The position may review the work of the Mapping Technician I & II positions.  Performs other related work for which the employee is capable and qualified to safely perform as assigned.

SENIOR MAPPING TECHNICIAN (3105)

This position performs work independently or under the limited direction of the Supervisor.  This position reviews completed work within the department for accuracy, completeness, and adherence to established procedures and standards, reporting results to the supervisor.  The position independently checks and updates CAD maps, database attribute files, the network model, including landbase updates, and reviews Mapping Technician I & II updates to the CAD maps and database attribute files.  This position checks Work Order/Project designs for accuracy, connectivity, completeness, and adherence to mapping standards.  This position creates and maintains all mapping standards and documentation.  This position reviews landbase changes and determines the impact to the mapping database, and provides guidance to the Mapping Technician I & II positions to accomplish the updates of the landbase information.  This position maintains the customer-to-transformer link and reconciles the automated assignment system when errors occur.  The position coordinates efforts with other departments to ensure that project design and as-built information is provided to the department in accordance with the required mapping standards.  This position prepares mapping software change requests and problem logs, proposes workaround solutions, and verifies and coordinates final problem resolution.  The position develops, prepares, and conducts training to the Mapping Technician I & II positions.  This position supports all the department needs related to the mapping software and AutoCAD software with regard to the software menus, macros, and scripts.  The position resolves any problems related to the department systems and the mapping process or data updates.  This position is expected to understand and perform all duties of a Mapping Technician I or II, if necessary.   Performs other related work for which the employee is capable and qualified to safely perform as assigned.

MASTER LINE CLEARANCE INSPECTOR (6199)

Directs, assigns and inspects all company and contract tree trimming maintenance activities. Assists other department personnel to ensure efficient operation of related activities. May be required to develop schedules, direct work assignments, dispatch crews, prepare job related reports, train departmental personnel and perform tree trimming activities. They will be required to get and maintain an ISA Certified Arborist license. Has direct contact with customers and promotes good public relations, and may be required to perform other duties for which are properly trained and competently and safely perform. Employees who obtain an ISA Certified Arborist license will be paid an amount equal to five (5) percent more than a line clearance inspector. The Company will pay any cost for getting and maintaining the ISA Certified Arborist license.

 

86

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

MATERIAL SPECIALIST I (6158)

Performs manual and clerical duties in connection with receiving, storing and issuing supplies, tools, and equipment; unloads and unpacks incoming materials; places, shelves and racks stock of machine, hand and construction tools; measures, counts, cuts, crates, marks and stencils materials, supplies, tools and equipment; keeps the premises clean; drives a car or pickup in local purchases of materials and equipment.  Operates special pole yard crane to receive, load and unload poles, large transformers and cable reels, switches and other heavy equipment, and determines location and reordering of same.  Supervises the orderly accumulation and removal of scrap materials in the pole yard.

MATERIAL SPECIALIST II (6186)

Performs manual and clerical duties in connection with receiving, storing and issuing supplies, tools, and equipment; unloads and unpacks incoming materials; places, shelves and racks stock of machine, hand and construction tools; measures, counts, cuts, crates, marks and stencils materials, supplies, tools and equipment; keeps the premises clean; operate vehicles as required to execute assigned tasks (including deliveries, purchases, etc). All Material Specialists II must have and maintain a Class A Commercial Drivers’ License (CDL) in the State of Nevada. The Company will responsible for the cost of any physical and license renewal fees. Operates special pole yard cranes to receive, load and unload poles, large transformer and cable reels, switches and other heavy equipment, and determines location and reordering of same. Supervises the orderly accumulation, and removal of scrap materials in the pole yard. This position will be paid an amount equal to fifty cents more than the Material Specialist I classification.

Failure to maintain a Class A, CDL in the State of Nevada will result in demotion to the Material Specialist I and reduction in the rate of pay to the Material Specialist I rate.

Om the initial filling of this classification, all current Material Specialist I will be offered the opportunity to advance to the Material Specialist II classification. After 1/1/09, any openings the Company chooses to fill in the Material Specialist II classification will be posted and will be filled through the bidding process.

MATERIAL UTILITY TECHNICIAN  (7093)

Performs unskilled and semi-skilled labor as necessary.  Keeps warehouse and outside areas clean.  May operate forklift for loading and unloading of materials for deliveries.  Drives warehouse vehicles for material deliveries and local purchases of material and equipment.  Two hours minimum upgrade if material is to be purchased during town run.  Must be able to obtain a CDL within 90 days of hire date.  May assist Material Specialist in putting away material and loading material for crews.  The ratio should not exceed 1 Material Utility Technician for 7 Material Specialists (1:7).  A Material Utility Technician shall not displace a Material Specialist.

MECHANIC SPECIALIST (3146)

Maintains all types of construction and transportation equipment and accessories. Diagnoses mechanical, hydraulic and electrical problems, makes and recommends repairs. Designs equipment modifications, constructs and installs parts and similar apparatus, including booms and winches, to accommodate the required changes. Performs pressure and structural welding, operates metal lathes, and other precision machinery, and does other related mechanical work as required.

METER SHOP DISPATCHER (5181)

Responsible for coordinating and scheduling all Meter Shop field activities; analyzing Customer Service Orders to determine a plan of optimum workload, crew size and man hours; coordinating work with service, maintenance and trouble crews as well as scheduling special meter tests and the installation of special metering devices. Dispatches crews as necessary, answers radio and telephones and does general office clerical work as required. Responsible for ordering Meter Shop related materials. Also, responsible for maintaining effective work relationships by communicating effectively and professionally with both internal and external customers.

 

87

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

METER TESTER (7085)

Inspects, tests, calibrates and repairs single-phase electric meters. Checks and regulates meter registration against standards at various load and power factors. Makes written reports of meter testing results. Performs other related work, including unskilled work in other Meter Services areas, for which the employee is capable and qualified to safely perform as assigned. Employees selected as a Meter Tester must have completed the Basic Math Class as a pre-qualification.

METERING UTILITY TECHNICIAN (6196)

Does unskilled work as necessary; keeps Journeyman, testers, and apprentices supplied with tools, materials, and supplies while assisting with a specific job; cleans working area and equipment including meter glass. Works with warehouse to assign meters to field workers. Operates other special equipment as required and drives truck or pickup in performance of duties. A metering utility technician shall not displace a tester, apprentice, or Journeyman. Performs other related work, including unskilled work in other meter services areas, for which the employee is capable and qualified to safely perform as assigned.

MULTI-TRADE TECHNICIAN I (7098)

Performs unskilled work as assigned.  Cleans work area and equipment.  Operates basic hand tools as required and drives truck or pickup in performance of duties.  Supplies tools and materials as needed and assists Multi-Trade Technician II and III.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MULTI-TRADE TECHNICIAN II (7099)

Requires general knowledge of building maintenance work including operating equipment, building management systems, painting, electrical, air conditioning, plumbing or carpentry.  Requires understanding of fire alarm systems, fire sprinkler systems and other fire suppression systems.  May be required to assist work in a lower classification.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MULTI-TRADE TECHNICIAN III (7100)

Supervises work and operations being performed.  Inspects, organizes, directs and coordinates work being performed by other skilled tradesmen.  Functions in a Multi-Trade Technician II capacity when necessary.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

PARTS SPECIALIST I, UTILITY FLEET (6157)

An employee who is familiar with automotive parts and supplies for a complex utility fleet and is qualified to perform, without direct supervision, and subordinate to the Supervisor in charge, duties relating to and, including inventory and stocking levels, purchase card functions, and the performance of duties relating to the ordering, receiving, shipping, handling, taking inventory, storing and disbursing of Fleet automotive and equipment related materials and supplies. Must operate Fleet/Corporate computer system to handle all aspects of shop repair orders relating to issuing and receiving parts, ordering and invoicing system including fuel, commercial work, labor and work order processing. Provides input to management regarding vendor selection, evaluation and performance. The employee shall become familiar with the departments accounting and data processing procedures and other applicable rules. May be required to update and operate data entry system for parts inventory control. Must be able to lift 50 lbs., shall be required to operate company vehicles within the scope of forgoing duties. May be required to provide general direction to any classification assigned to the Parts Specialist in performing the work herein defined. May be required to assist with or perform work in a lower classification and other related work for which the employee is capable and qualified to perform as assigned. Must possess good communication skills, both oral and written, and general knowledge of Fleet terminology, and practices.

 

88

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

PARTS SPECIALIST II, UTILITY FLEET (6156)

An employee who is familiar with automotive parts and supplies for a complex utility fleet and is qualified to perform, without direct supervision, and subordinate to the Supervisor in charge, duties relating to and, including inventory and stocking levels, purchase card functions, and the performance of duties relating to the ordering, receiving, shipping, handling, taking inventory, storing and disbursing of Fleet automotive and equipment related materials and supplies. Must operate Fleet/Corporate computer system to handle all aspects of shop repair orders relating to issuing and receiving parts, ordering and invoicing system including fuel, commercial work, labor and work order processing. Provides input to management regarding vendor selection, evaluation and performance. The employee shall become familiar with the departments accounting and data processing procedures and other applicable rules. May be required to update and operate data entry system for parts inventory control. Must be able to lift 50 lbs., shall be required to operate company vehicles within the scope of forgoing duties. Will be required within 30 days after being awarded the position to obtain and maintain a Class A commercial driver’s license in the State of Nevada, The Company will be responsible for the cost of any physical and license renewal fees. Classification will receive 50 cents over the wage rate of the Parts Specialist I, Fleet classification. May be required to provide general direction to any classification assigned to the Parts Specialist in performing the work herein defined. May be required to assist with or perform work in a lower classification and other related work for which the employee is capable and qualified to perform as assigned. Must possess good communication skills, both oral and written, and general knowledge of Fleet terminology, and practices.

*The 50 cent increase for the Part Specialist II classification over the Specialist I is to compensate for the Class A CDL requirement.

RELAY ELECTRICIAN I (6198)

With supervision and oversight regularly and customarily inspects, tests, adjusts, calibrates, repairs, and installs all types of system protection and control equipment.  Performs the work required for the installation, maintenance, repair, and adjustment of automatic controls and equipment protection devices concerned with the operation of generating equipment as it affects the system, power transformers, transmission systems, distribution systems, and customer facilities.  With supervision the Relay Electrician I is responsible for certification of all related wiring, operational checks, and taking and evaluating in-service test data.  Must be a Journeyman substation electrician with two years of experience as a Journeyman, be a qualified Nevada Power Company substation switchman, have formal training in mathematics progressing through trigonometry and be knowledgeable in electrical and electronic theory, including but not limited to microprocessors, polyphase circuits, and diagrams.  Upon occasion or in an emergency the Relay Electrician I may be required to perform such other duties as assigned.  This position is not to be considered a permanent position but is a training position for the Relay Electrician II position.  The Relay Electrician I shall qualify for the Relay Electrician II position by demonstrating, on-the-job, that he or she has acquired the necessary skills to qualify and then pass a written proficiency exam.

RELAY ELECTRICIAN II (6107)

With almost no supervision and oversight be capable of working independently to regularly and customarily inspects, tests, adjusts, calibrates, repairs and installs all types of system protection and control equipment. Also performs the work required for the installation, maintenance, repair, and adjustment of automatic controls and equipment protection devices concerned with the operation of generating equipment as it affects the system, power transformers, transmission systems, distribution systems, and customer facilities.

Download, verify, and troubleshoot logic programming and logic systems on microprocessor relays, and specialized substation computing systems.

Is responsible for certification of all related wiring, operational checks, and taking and evaluating in service test data. Must be a Journeyman substation electrician, with two years of experience as a Journeyman, be a qualified Nevada Power Company substation switchman, have formal training in mathematics progressing through trigonometry and be knowledgeable in electrical and electronic theory, including but not limited to microprocessors, polyphase circuits and diagrams; upon occasion or in an emergency, may be required to perform such other duties as assigned.

 

89

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

RELIEF LINE TROUBLEMAN (6187)

Performs the duties of a Line Troubleman as described in this Exhibit I. The relief Line Troubleman shall be assigned to any shift other than the usual schedule for purposes of providing relief coverage for an absent Line Troubleman.

SUB LEAD LINEMAN

In the absence of appropriate supervision and when directed, leads, assists, and works with other departmental personnel to ensure efficient operation of related activities. May be required to develop schedules, direct work assignments, prepare job related reports, complete other administrative duties, function in a journeyman lineman capacity, and perform other work as needed. The Sub Lead Lineman classification will be paid an amount equal to 5% greater than a Journeyman Lineman. This classification is not intended to replace the lead classification; this Sub Lead Lineman classification is for two man crews when such crews are performing, meter sets, DCA work, standbys, service work, fault location and any and all tasks for which they are properly trained and can competently and safely perform.

The Sub Lead Lineman will be appointed and chosen by the Company in its discretion.

SUBSTATION ELECTRICIAN (6122)

Performs a variety of skilled electrical and mechanical work in the construction, maintenance and operations of substations and switchyards. Must be qualified to install, erect, maintain, switch, test and repair all substation equipment including, but not limited to, transformers, regulators, circuit breakers, switchgear, switchboard bus and cable work. Must be able to lay out, assemble, install, test and maintain fixtures and wiring. Upon occasion or in an emergency, may be required to perform such other work duties as assigned.

SUBSTATION GROUNDMAN (6189)

Performs semi-skilled work functions and tasks as assigned by supervisor, Substation Lead, Journeyman or apprentice, supplies tools and materials while assisting with specific jobs; Works under the supervision of Substation Lead or Journeyman. Work assignments will provide training to enhance job knowledge and skills for progression in career path towards electrical apprenticeship. At no time, shall a groundman be allowed to work on energized equipment or lines. Responsible for keeping job sites clean and may be required to perform such other duties as assigned.

SUBSTATION INSPECTOR (6121)

Conducts inspections of Substations and Substation Equipment. Must be a Journeyman substation electrician. Must be able to work alone and be responsible for scheduling their own work to meet departmental schedules; Responsible for scheduling and performing preventative maintenance on substation battery systems. Performs switching in substations required for dispatch to clear line and equipment for other entities and load relief. Responsible for providing monthly and bi-monthly load reads into the load database. May also be asked to perform some minor maintenance work on substation equipment and other duties as assigned that they are trained and qualified to perform.

SURVEY INSTRUMENT TECHNICIAN (6190)

Assists the Surveyor/Crew Chief in the performance of survey and survey related activities. Must possess a working knowledge of the theories and principles of geometry. Must be able to operate and maintain all survey and survey related equipment and is responsible for the accuracy of all measurements. Is familiar with construction layout and staking and possesses the physical ability to perform such duties in various terrain and weather conditions. Must possess basic knowledge of Land Survey principles and practices and actively pursues performance excellence. Must be able to read and understand construction/engineering plans and keep accurate, legible field notes. Performs research and calculations in support of the Survey/Crew Chief. Is responsible for basic maintenance, cleaning and stocking of work truck and other vehicles used in the performance of the survey crew’s duties. In the absence of the Surveyor/Crew Chief, must be able to act as Crew Chief. Performs such other duties as may be assigned.

 

90

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

SURVEYOR (3178)

Directs the work and activities of the Survey Crew in the performance of measurements upon the land of features and fixtures of Company owned land and land rights, construction layout and staking of improvements and facilities, and other survey related activities in support of Company objectives. Maintains and operates all survey and survey related equipment. Checks plans for accuracy, performs research, calculations and other field checks to insure correctness, maintains data collector files and oversees survey crew to make sure correct survey procedures and safety requirements are met. Possesses fundamental knowledge of Land Survey principles and practices and actively pursues performance excellence. The Surveyor shall be responsible for the survey crews activities in the performance of their duties. Must possess a valid ProfessionalLand Surveyors license. Should the license expire or be revoked, the employee will return to the classification and rate of pay of Crew Chief.  The Company may require a Surveyor to provide documentation of a current Professional Land Surveyor’s license on an annual basis.  Performs such other duties as may be assigned.

TOOL COMPLIANCE TECHNICIAN (6184)

Administers the live line tool testing and maintenance program per 29 CFR 1910.269 Company wide, the high and low voltage rubber glove testing program per 29 CFR 1910.269 Company wide, the atmospheric test instruments program per 29 CFR 1910.269 and the tool inventory program and protective ground testing program.  Performs live line tool testing and maintenance and administers records.  Administers high and low voltage rubber protective equipment testing and record maintenance. Maintains tool inventory and administers control procedures and activities.  Calibrates atmospheric test instruments.  Shall be responsible for protective ground testing/maintenance. May perform the duties of Tool Repairer, as needed.

TOOL REPAIRER (6183)

Receives, stores, issues and maintains records for tools and similar items used in connection with the construction, maintenance and repair of the Company’s transmission and distribution systems, including vehicles, metering and communication maintenance and related services. Does minor repair work on hot sticks, hoists, pumps, drills and other tools associated with T&D operations. Refuels Company vehicles, makes and repairs hot jumpers, hand lines, rope blocks and cable slings, etc. May work as a groundman or a clerk driver if required.

TRAINER-LINES (6105) / TRAINER-SUBSTATION (6104)

Responsible for administration development, administration and evaluation of apprenticeship program for Journeyman classification in accordance with Company guidelines and industry standards. Provides classroom instruction and field training for qualified groundman, apprentice, and Journeyman classifications. Will be responsible for apprentice testing and evaluation, maintenance of all apprentice and Journeyman training records. Provides reports and recommendations to the apprentice committee. Conducts assessments and evaluations for program effectiveness and performance. Performs other related duties as required and may be required to work in classification as needed.

UNDERGROUND INSPECTOR (6172)

Will be responsible for inspecting the installation of conduits, main trenches and all system improvement projects. Inspects underground sub-structures all in accordance with Company specifications and standards. Will perform survey work in determining alignment locations for right-of-way acquisition as required by various departments. Will assist the Electrical Inspector in all aspects of the job. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

UNDERGROUND LINE LOCATOR (6173)

Shall be responsible for all aspects of line location including maintaining and understanding equipment necessary to complete all line locates. Shall be responsible for accuracy, reading and understanding all engineering blueprints, keeping accurate office and field notes, coordinating between contractors and customers, research records for needed information to perform all duties in line locates.  May report to different locations and may perform other duties.

 

91

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

UTILITY DESIGN COORDINATOR I (3107)

This entry-level position completes design work of a straightforward and standardized nature and identifies project specific customer needs and expectations for electric utility improvements. Responsible for the preparation of new improvement designs, work orders and cost estimates for new business construction. This position may be the central point of contact for external customers, developers, contractors, engineering firms, local agencies, utilities and governmental entities. Designs and/or coordinates entry-level to more complex electric utility improvements. Focuses on the identification of customer needs regarding project specific electric utility design requirements, standards, policies and establishes project specific business relationships and guides the customer through the New Business process. Focuses on ensuring service commitments are delivered and will create, negotiate and administer financial and contractual agreements with the external customer. This position may perform independently or under the general direction of a Utility Design Coordinator II or Senior Project Coordinator.  Provides high level of customer service to internal and external customers. May complete field checks of customer service orders for meter sets on new electric utility improvements.  Responsible for verification of voltage, amperage and panel size for various types of meter sets, and ensures that a final inspection from the appropriate government entity has been issued, the panel is energized and that identification is clearly posted on the panel and building. Required to operate a vehicle for the Company.  Responsible for design quality assurance and ensuring a quality product for internal and external customers. Performs other related work, including underground line location, for which the employee is capable and qualified to safely perform as assigned

UTILITY DESIGN COORDINATOR II (3108)

This position performs complete design work of a straightforward and standardized nature and identifies project specific customer needs and expectations for electric utility improvements. Responsible for the preparation of new improvement designs, work orders and cost estimates for new business construction. May provide training, development and mentoring to the Utility Design Coordinator I. This position may be the central point of contact for external customers, developers, contractors, engineering firms, local agencies, utilities and governmental entities. Designs and/or coordinates entry-level to very complex, electric utility improvements. Focuses on the identification of customer needs regarding project specific electric utility design requirements, standards and policies. Establishes project specific business relationships and guides the customer through the New Business process. Also expected to understand and be capable of performing all duties of a Utility Design Coordinator I. Focuses on ensuring service commitments are delivered and will create, negotiate and administer the financial and contractual agreements with the external customer, including government entities. This position may perform under the direction of a Senior Project Coordinator. Required to operate a vehicle for the Company. Responsible for design quality assurance and ensuring a quality product for internal and external customers. Performs other related work for which the employee is capable and qualified to safely perform as assigned.

SENIOR PROJECT COORDINATOR (3109)

This position identifies project specific customer needs and expectations for new electric utility business development. This position is the central point of contact for external customers, developers, contractors, engineering firms, local agencies, utilities and governmental entities. Focuses on the identification of customer needs regarding project specific electric utility design requirements. Establishes project specific business relationships and guides the customer through the New Business process. Focuses on ensuring service commitments are delivered and will create, negotiate and administer the financial and contractual agreements with the external customer, including government entities. Coordinates moderately complex, to very complex, new electric utility improvements. Responsible for the preparation of  electric utility improvement designs, work orders, cost estimates and contract administration pertaining to budget jobs for new construction or system improvements, public works, road improvements and government projects. Expected to understand and perform all duties of a Utility Design Coordinator I or II. Provides coaching, direction and mentoring to the Utility Design Coordinator I & II. Required to operate a vehicle for the Company. Responsible for design quality assurance and ensuring a quality product for internal and external customers. Performs other related work, including maintaining a close working relationship with internal partners to facilitate continuous improvement opportunities and attainment of cost per customer goals, for which the employee is capable and qualified to safely perform as assigned.

 

92

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%
3102	Rodman Chainman	1	23.32	23.55
	2nd Six Months	2	25.51	25.77
	3rd Six Months	3	25.72	25.98
	4th Six Months	4	27.02	27.29
	5th Six Months	5	28.40	28.68
3103	Tech I, Mapping	1	22.10	22.32
	2nd Six Months	2	22.65	22.88
	3rd Six Months	3	23.19	23.42
	4th Six Months	4	23.78	24.02
	5th Six Months	5	24.37	24.61
	6th Six Months	6	24.99	25.24
	7th Six Months	7	25.60	25.86
3104	Tech II, Mapping	1	25.99	26.25
	2nd Six Months	2	26.53	26.80
	3rd Six Months	3	27.04	27.31
	4th Six Months	4	27.59	27.87
	5th Six Months	5	28.15	28.43
	6th Six Months	6	28.69	28.98
	7th Six Months	7	29.27	29.56
	8th Six Months	8	29.89	30.19
3105	Tech Sr, Mapping	1	30.09	30.39
	2nd Six Months	2	30.64	30.95
	3rd Six Months	3	31.40	31.71
	4th Six Months	4	32.19	32.51
	5th Six Months	5	32.96	33.29
	6th Six Months	6	33.78	34.12
	7th Six Months	7	34.60	34.95
3107	UDC I	1	23.40	23.63
	2nd Six Months	2	24.10	24.34
	3rd Six Months	3	24.81	25.06
	4th Six Months	4	25.58	25.84
	5th Six Months	5	26.33	26.59
	6th Six Months	6	27.11	27.38
	7th Six Months	7	27.93	28.21

93

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%
	8th Six Months	8	28.79	29.08

3108	UDC II	1	30.94	31.25
	2nd Six Months	2	31.87	32.19
	3rd Six Months	3	32.84	33.17
	4th Six Months	4	33.81	34.15
3109	Coordinator Senior, Projects	1	36.39	36.75
	2nd Six Months	2	37.47	37.84
	3rd Six Months	3	38.79	39.18
	4th Six Months	4	40.15	40.55
	5th Six Months	5	41.56	41.98
3146	Mechanical Specialist	1	40.09	40.49
3178	Surveyor	1	40.60	41.01
5144	Clerk Dispatcher	1	35.10	35.45
5145	Mat Spec/LG/FSR	1	30.25	30.55
	2nd Six Months	2	31.38	31.69
	3rd Six Months	3	32.67	33.00
5181	Meter Shop Dispatcher	1	29.61	29.91
6054	Lead Comm Electrician	1	45.69	46.15
6055	Lead Relay Electrician	1	46.66	47.13
6056	Lead Substation Electrician	1	44.45	44.89
6057	Lead Lineman	1	44.89	45.34
6058	Lead Metering Electrician	1	44.45	44.89
6062	Lead Underground Inspector	1	38.01	38.39
6080	Lead Fleet Services Mechanic	1	43.56	44.00

94

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

6086	Lead Material Specialist T&D	1	35.94	36.30
6089	Lead Surveyor	1	44.67	45.12
6100	Line Clearance Inspector	1	27.44	27.71
6104	Trainer Substation	1	44.45	44.89
6105	Trainer Lines	1	44.89	45.34
6107	Relay Electrician II	1	42.43	42.85
6108	Comm Electrician II	1	42.43	42.85
6110	Field Inspector	1	41.63	42.05
6111	Circuit Inspector	1	36.35	36.71
6112	Electrical Inspector	1	42.83	43.26
6113	Line Troubleman	1	42.84	43.27
6121	Substation Inspector	1	42.43	42.85
6122	Substation Electrician	1	40.41	40.81
6123	Journeyman Lineman	1	40.80	41.21
6124	Journeyman Metering Electrician	1	40.41	40.81
6130	Welder,Company Wide	1	40.41	40.81
6136	Lines Groundman	1	21.86	22.08
	2nd Six Months	2	22.60	22.83
	3rd Six Months	3	23.32	23.55
	4th Six Months	4	24.22	24.46
	5th Six Months	5	25.15	25.40

95

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

	6th Six Months	6	26.12	26.38
	7th Six Months	7	27.02	27.29
6150	Equipment Mechanic	1	39.60	40.00
6151	Fleet Maintenance Technician	1	28.47	28.75
	2nd Six Months	2	29.32	29.61
	3rd Six Months	3	30.20	30.50
	4th Six Months	4	31.08	31.39
	5th Six Months	5	31.89	32.21
6158	Material Specialist I T&D	1	30.25	30.55
	2nd Six Months	2	31.38	31.69
	3rd Six Months	3	31.67	33.00
6159	Warehouse Utility Tech T&D	1	22.42	22.64
	2nd Six Months	2	23.30	23.53
	3rd Six Months	3	24.14	24.38
6166	Equipment Operator	1	36.08	36.44
6172	Underground Inspector	1	30.02	30.32
	2nd Six Months	2	31.25	31.56
	3rd Six Months	3	32.31	32.63
	4th Six Months	4	33.45	33.78
	5th Six Months	5	34.56	34.91
6173	Underground Line Locator	1	22.06	22.28
	2nd Six Months	2	23.15	23.38
	3rd Six Months	3	24.34	24.58
	4th Six Months	4	25.56	25.82
6177	High Boom Operator	1	34.56	34.91
6180	Line Patrolman	1	41.63	42.05
6182	Fleet Utility Tech	1	25.01	25.26
	2nd Six Months	2	25.89	26.15

96

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

	3rd Six Months	3	26.71	26.98
	4th Six Months	4	27.60	27.88
6183	Tool Repairer	1	33.62	33.96
6184	Technician, Tool Compliance	1	35.31	35.66
6185	Comm Groundman	1	21.86	22.08
	2nd Six Months	2	22.60	22.83
	3rd Six Months	3	23.32	23.55
	4th Six Months	4	24.22	24.46
	5th Six Months	5	25.15	25.40
	6th Six Months	6	26.12	26.38
	7th Six Months	7	27.02	27.29
6156	Parts Specialist II, Utility Fleet	1	30.75	31.06
	2nd six months	2	31.66	31.98
	3rd six months	3	32.59	32.92
	4th six months	4	33.54	33.88
	5th six months	5	34.55	34.38
6157	Parts Specialist I, Utility Fleet	1	30.25	30.55
	2nd six months	2	31.15	31.46
	3rd six months	3	32.08	32.40
	4th six months	4	33.04	33.37
	5th six months	5	34.04	34.38
6158	Material Specialist II T&D	1	33.18	33.51
6187	Relief Line Troubleman	1	43.66	44.10
6188	Clerk Driver	1	29.65	29.95
	2nd Six Months	2	30.80	31.11
	3rd Six Months	3	31.97	32.29
	4th Six Months	4	33.10	33.43
6189	Substation Groundman	1	21.86	22.08
	2nd Six Months	2	22.60	22.83

97

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

	3rd Six Months	3	23.32	23.55
	4th Six Months	4	24.22	24.46
	5th Six Months	5	25.15	25.40
	6th Six Months	6	26.12	26.38
	7th Six Months	7	27.02	27.29
6190	Survey Instrument Tech	1	30.02	30.32
	2nd Six Months	2	31.25	31.56
	3rd Six Months	3	31.31	32.63
	4th Six Months	4	33.45	33.78
	5th Six Months	5	34.56	34.91
6196	Metering UtilityTech-Mtr Svc	1	16.38	16.54
	2nd Six Months	2	17.27	17.44
	3rd Six Months	3	18.10	18.28
	4th Six Months	4	18.97	19.16
	5th Six Months	5	19.84	20.04
	6th Six Months	6	20.69	20.90
	7th Six Months	7	21.56	21.78
6197	Communications Electrician I	1	40.91	41.32
6198	Relay Electrician I	1	41.53	41.95
6199	Master Lines Clearance Inspector	1	28.81	29.10
7013	App Equip Mechanic	1	31.29	31.60
	2nd Six Months	2	32.15	32.47
	3rd Six Months	3	33.04	33.37
	4th Six Months	4	33.95	34.29
	5th Six Months	5	34.95	35.30
	6th Six Months	6	36.98	37.35
	7th Six Months	7	39.60	40.00
7020	Apprentice Lineman	1	22.44	22.66
	2nd Six Months	2	24.48	24.72
	3rd Six Months	3	26.52	26.79
	4th Six Months	4	28.56	28.85

98

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

	5th Six Months	5	30.60	30.91
	6th Six Months	6	32.64	32.97
	7th Six Months	7	34.68	35.03
	8th Six Months	8	36.72	37.09
7021	App Substation Electrician	1	29.99	30.29
	2nd Six Months	2	31.22	31.53
	3rd Six Months	3	32.27	32.59
	4th Six Months	4	33.40	33.73
	5th Six Months	5	34.52	34.87
	6th Six Months	6	35.62	35.98
	7th Six Months	7	36.74	37.11
	8th Six Months	8	37.87	38.25
	9th Six Months	9	40.41	40.81
7022	App Metering Electrician	1	29.99	30.29
	2nd Six Months	2	31.22	31.53
	3rd Six Months	3	32.27	32.59
	4th Six Months	4	33.40	33.73
	5th Six Months	5	34.52	34.87
	6th Six Months	6	35.62	35.98
	7th Six Months	7	36.74	37.11
	8th Six Months	8	37.87	38.25
	9th Six Months	9	40.41	40.81
7024	App Comm Electrician	1	29.99	30.29
	2nd Six Months	2	31.22	31.53
	3rd Six Months	3	32.27	32.59
	4th Six Months	4	33.40	33.73
	5th Six Months	5	34.52	34.87
	6th Six Months	6	35.62	35.98
	7th Six Months	7	36.74	37.11
	8th Six Months	8	37.87	38.25
	9th Six Months	9	40.41	40.81
7085	Meter Tester	1	23.94	24.18
	2nd Six Months	2	25.01	25.26

99

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

7093	Material Utility Technician	1	22.42	22.64
	2nd Six Months	2	23.30	23.53
	3rd Six Months	3	24.14	24.38
7094	Maintenance Technician	1	26.71	26.98
	2nd Six Months	2	27.60	27.88
	3rd Six Months	3	28.47	28.75
	4th Six Months	4	29.32	29.61
	5th Six Months	5	30.20	30.50
	6th Six Months	6	31.08	31.39
	7th Six Months	7	31.89	32.21
7095	Chief, Crew	1	36.52	36.89
	2nd Six Months	2	37.37	37.74
	3rd Six Months	3	38.13	38.51
	4th Six Months	4	38.80	39.19
	5th Six Months	5	39.62	40.02
7096	Maintenance Utility Tech	1	16.38	16.54
	2nd Six Months	2	17.27	17.44
	3rd Six Months	3	18.10	18.28
	4th Six Months	4	18.97	19.16
	5th Six Months	5	19.84	20.04
	6th Six Months	6	20.69	20.90
	7th Six Months	7	21.56	21.78
7097	Facilitator, Design & Const	1	42.83	43.26
7098	Tech, Multi-Trade I	1	23.74	23.98
7099	Tech, Multi-Trade II	1	28.12	28.40
7100	Tech, Multi-Trade III (Lead)	1	34.37	34.71

100

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

March 1, 2004

Mr. Jim Anzinger

International Brotherhood of Electrical Workers

Local Union #396

3520 Boulder Hwy

Las Vegas, NV 89121

Letter of Understanding

Dear Mr. Anzinger,

This letter will document the Agreement between the International Brotherhood of Electrical Workers, Local #396, and Nevada Power Company relative to the duties of IBEW Local Union #396 represented Crew Chiefs and Surveyors employed in the Land Survey, Land Services Department.

It is agreed and understood that job assignments may be made whereby the

Crew Chief or Surveyor will be allowed to completed the assigned project from “field to finish”. All such duties of said “field to finish” projects, normally accomplished by Nevada Power Company MPAT employees, will be accomplished by the represented employee with the help and aid of MPAT employees. No adjustments to pay will be made.

During the times when a Crew Chief or Surveyor is performing duties other than field duties, relative to these specific projects, they will under the direction of the Lead Surveyor, coordinate their assigned on-going fieldwork with crew members.  When an Instrument Technician is assigned duties normally associated with Crew Chief or a Surveyor, the Instrument Technician shall be up-graded with appropriate pay adjustments in accordance with the Collective Bargaining Agreement.

Performance reviews will be made in accordance with the Collective Bargaining Agreement with respect to field performance only.

This is a non-precedent setting agreement and may be rescinded by notification in writing by either party.

AGREED:

/s/Zelender Dye

Sr. Labor Relations

Nevada Power Company

/s/James Anzinger

Business Manager/Financial Secretary

IBEW Local #396

101

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

SUBSTATIONS

FOUR-TEN Hour Shift (4/10) Schedule

THE FOLLOWING PROVISIONS SHALL SUPERSEDE THE CORRESPONDING ARTICLES OF THE COLLECTIVE BARGAINING AGREEMENT FOR THE PURPOSE OF ESTABLISHING WORKING CONDITIONS APPLICABLE TO THOSE EMPLOYEES ASSIGNED TO THE FOUR-TEN HOUR SHIFT (4/10) SCHEDULE in the following classifications:

·   Substation Electrician

·   Lead Substation Electrician

·   Substation Inspector

·   Substation Groundman

·   Maintenance Technician

·   Tool Compliance Technician

·   Companywide Welder

·   Apprentice Substation Electrician

·   Trainer - Substation

T & D ARTICLE NO. 6

Working Hours and Rates of Pay

FOUR-TEN Hour Shift (4/10) Schedule

6.1 WORK DAY:  Ten (10) hours in any one day shall constitute the workday.

6.1 REGULAR DAY-SHIFT EMPLOYEES: Regular day shift employees are those employees who are assigned to shifts, which are established on a Monday through Friday schedule and work a shift, which begins between the hours of 7:00am and 11:59am.  When mutually agreed to by the Union and Company, the day shift starting time may be scheduled as early as 6:00am to take advantage of daylight hours.

6.1 WORK WEEK: Four-ten hour (4/10) days shall constitute the basic work week.  These workdays will be some combination of the days, Monday through Friday, and will be consecutive unless mutually agreed to by the parties.

6.3.1   OVERTIME:  Time worked in excess of ten (10) hours per day shall be considered overtime and will be paid for at one and one-half (1 1/2) times the regular established wage rate except as otherwise provided in this article.  Work scheduled in the three (3) hours immediately preceding normal starting time shall be at time and a half (unless mutually agreed upon to take advantage of daylight hours).

ARTICLE 10

10.3 COMPANY HOLIDAYS: When a holiday falls on an employee's regularly scheduled day off, the holiday shall be observed on that day for pay purposes.  The last scheduled non-overtime work day immediately preceding the holiday or the non-overtime work day immediately following the holiday shall be observed as the regularly scheduled day off for the purposes of this article.

ALL PARAGRAPHS NOT LISTED SHOULD BE CONSIDERED UNCHANGED FROM THE COLLECTIVE BARGAINING AGREEMENT.

102

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Either the Union or the Company can cancel this agreement with sixty (60) days written notice.

/s/Trudy Haszlauer

Manager, Labor Relations

2-2-11

/s/Charlie Randall

Business Manager

IBEW Local #396

2-8-11

103

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION

ARTICLE NO. 4

Union Activity

4.3              CONTRACTING WORK:

In case the Company should contract any type ofwork customarily performed by bargaining unit employees, the Company shall, before awarding such contract, advise the contractor that the work is to be done under not less than the terms and conditions pertaining to hours and wages set forth in this Agreement. Upon award of such contract, the Company shall notify the Union in writing within thirty (30) calendar days of any and all contracts awarded of such contractor and the nature of the work being performed. The Company will not contract any of its construction and maintenance work while having available competent employees to do such work. In the event the Company has employees on layoff with recall rights, the Company will not establish contracts for work that is customarily performed by such bargaining unit employees unless the affected employees are not qualified to perform the work (as defined in Article 5.4 LAYOFF PROVISIONS), or the work requires the use of special construction or other equipment which the Company does not possess. If the Company has employees in layoff status who are qualified to perform work, which the Company intends to contract, the Company may recall these employees for the term of the contracted work without creating the liability for an additional severance in accordance with Article 5 (STATUS OF EMPLOYEES) of this Agreement.

104

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION

ARTICLE NO.  6

Working Hours and Rates of Pay

6.1              DEFINITIONS:

SHIFT:  Hours of work.

SCHEDULE:  Days and hours of work.

WORK DAY: Eight (8) hours in any one (1) day shall constitute the work day; however the Company and Union may enter into Agreements which establish alternative work schedules involving work days which have more than eight hours.

WORK WEEK: Five (5) consecutive work days, regularly scheduled between the hours of 12:01 am, Monday, and 12:00 midnight, Sunday, shall constitute the basic work week.  The basic work week of regular day-shift employees shall be from Monday through Friday and reflect a schedule of forty (40) hours of straight-time work.

REGULAR DAYS OFF: Days off shall be consecutive, however, they may not be within the basic workweek.

REGULAR DAY-SHIFT EMPLOYEES: Regular day shift employees are those employees who are assigned to shifts, which are established on a Monday through Friday schedule and work a shift, which begins between the hours of 7:00 am and 11:59 am.  When mutually agreed to by the Union and Company, the day shift starting time may be scheduled as early as 6:00 am to take advantage of daylight hours.

SEVEN DAY COVERAGE: A schedule of fixed or rotating shifts that cover seven (7) days per week, twenty-four (24) hours per day.

SHIFT EMPLOYEES: Shift employees are all employees not defined as regular day-shift employees.  This includes employees assigned to fixed shifts and seven (7) day coverage.

SHIFT DESIGNATIONS:No shift periods shall start between the hours of 12:01 am and 5:59 am, unless mutually agreed to by memorandum of understanding between the Company and the Union.  The follow designations shall apply:

FIRST SHIFT: All eight (8) hour shift periods regularly scheduled to begin at 6:00 a.m., or thereafter but before 12:00 noon shall be designated as first shifts.

SECOND SHIFT: All eight (8) hour shift periods regularly scheduled to begin at 12:00 noon or thereafter but before 8:00 p.m., shall be designated as second shifts.

THIRD SHIFT: All eight (8) hour shift periods regularly scheduled to begin at 8:00 p.m., or thereafter but before 12:01 a.m., shall be designated as third shifts.

SHIFT DIFFERENTIAL: An incremental increase for working on a second or third shift.

SHIFT PREMIUM: An incremental increase for all hours worked outside of the employee's previous schedule for the first five (5) working days of a newly established permanent, temporary or emergency schedule.

SHORT CHANGE: A transfer from one established schedule to another with only one shift off between schedules.

105

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

COMPANY HEADQUARTERS: Any headquarters established for the purpose of engaging in work covered by this Agreement when such work will continue for an indeterminate period of time.

6.4 OVERTIME: In computing overtime, intermission taken out for meals served other than on the job shall be deducted, and any holiday or vacation paid in that pay period will be considered as time worked.

NO PYRAMIDING OF OVERTIME:  The employee will only be entitled to the highest single premium rate applicable to the work assigned by the CBA.  There will be no pyramiding of overtime.

TIME AND A HALF: Except as otherwise provided in this Article, the following situations shall require payment at one and one-half (1 1/2) times the regular established wage rate:

• Time worked in excess of eight (8) hours per day.

• Time worked in excess of any five (5) scheduled workdays in that workweek.

• Work scheduled in the three (3) hours immediately preceding the normal starting time.

• Employees scheduled to work on an observed holiday.

• Employees on seven (7) day coverage who are scheduled or called out for overtime except as defined in "Double Time."

• Employees who are scheduled for overtime and such is canceled per Article 6.9 (REQUIRED NOTICE FOR OVERTIME).

DOUBLE TIME: Except as otherwise provided in this Article, the following situations shall require payment at two (2) times the regular established wage rate:

• Employees, other than those assigned to seven (7) day coverage, which are scheduled to work within the first five (5) hours of the eight (8) hour period immediately preceding the normal starting time regardless of the day of the week.

• Employees who work on the second day of a two day off period, or on the second or fourth days off of a four (4) days off period with an overtime minimum as provided in Article 6.7 (CALL-OUTS).

DOUBLE TIME AND A HALF: Except as otherwise provided in this Article, the following situations shall require payment at two and one-half (2 1/2) times the regular established wage rate:

• All time worked in excess of sixteen (16) consecutive hours.

BREAK PERIOD: Employees entitled to pay at this rate will continue at this rate until they have been released for a period of at least six (6) continuous hours.  Any break of six (6) hours will be considered an interruption of continuous work time.  It is understood that any employee may be returned to work exactly six (6) hours from their most recent release, satisfying the required break.  It is also understood that any employee released for such a break may be called back to work before six (6) hours have elapsed.

MEAL PERIODS:Meal periods while working overtime will not be considered as part of the six (6) hour break and will not be considered time worked, unless employees are directed to work through their meal period.  Employee's unpaid meal period which occurs during regular work hours will be included in the computation of the six (6) hour break, when this break is

106

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

calculated from the end of the employee's last regular shift.  Accordingly, an employee may be called out five and one-half (5 1/2) hours from the end of their last regular shift without creating a requirement for this rate.

STRAIGHT TIME PAY: Employees sent home for a six (6) hour break will not lose any straight time pay for normally scheduled hours, as a result of such a break.

Example:

Employees assigned to a 7:00 am to 3:30 pm shift and released two (2) hours early so they

may have a six (6) hour break before a scheduled outage would be paid for the two (2) hours

at the straight time rate and this would satisfy the six (6) hour break.

Employees must use any rest time pay accumulated as a result of an overtime assignment before these provisions would apply. If an employee's accumulated rest time does not cover the entire six (6) hour break, the employee will receive straight time pay for any regularly scheduled hours not worked due to this break.

6.5 OVERTIME EQUALIZATION: The Company will endeavor to distribute overtime work as evenly as possible among those employees qualified to perform such work. For the purpose of distributing overtime, the Company will maintain and post overtime lists in each sub-department indicating time offered and time worked. Each department will create policies and procedures (BY LOCATION, SHIFT – as defined by Article 6.1 AND CLASSIFICATION), for overtime equalization through labor/management meetings.

6.6              PAY PROVISIONS:

PAY DAYS:  Pay days shall be at biweekly intervals.

WAGES:  The schedule of job classifications and wage rates, as mutually agreed to, are made a part of this Agreement, and are marked "Exhibits I and II" respectively.

Wages shall be paid at biweekly intervals on the Thursday following the close of the two-week pay period provided that if the regular payday falls on a holiday, payment shall be made on the preceding workday.

SPECIAL PAY REQUESTS: The Company recognizes there will be circumstances such as weeks of vacation and vacation in association with holidays, which will create special requests of the payroll department.  Unless the situation is an emergency, all special checks will be limited to individuals who are absent for at least the Wednesday through Friday of a pay week.  Exceptions to this practice will require written approval from the department manager and must be presented to payroll no later than forty-eight (48) hours in advance of the requested time for payment.

RECOVERING OVERPAYMENTS: Deductions from an employee's wages, to recover overpayments made in error, will not be made unless the employee is notified prior to the end of the month following the month in which the check in question was delivered to the employee.  The Company and the employee will agree upon a schedule for re-payment.

6.7 CALL-OUTS:

TWO-HOUR MINIMUM:  Employees called out for overtime duty shall receive at least two (2) hours pay.  Reasonable travel time (defined below) to and from home will be considered as time worked for the purpose of satisfying the two (2) hour minimum, and will be paid at the appropriate overtime rate.

Example #1

Employees called out who work two (2) hours and travel one (1) hour (round trip) will be paid

for three (3) hours.

107

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Example #2

Employees called out who work fifteen (15) minutes and travel one (1) hour (round trip) will

be paid for two (2) hours.

Example #3

Employees called out who work into their regular shift shall be paid the appropriate overtime

premium for at least two (2) hours, which includes travel time to work only.  This does not

change the normal starting time for the purpose of extending the shift.

MULTIPLE CALL-OUTS:  Employees called-out more than once in the twenty-four (24) hour period from midnight one day to midnight the following day shall be paid at least the two (2) hour minimum mentioned above for the first call. For subsequent calls, employees shall be paid for a one (1) hour minimum with the same travel time considerations mentioned above. For the purpose of this section, concurrent calls or successive calls without a break in work time shall be considered as a single call.

TRAVEL TIME: Employees are entitled to travel time according to the following:

Locations	Las Vegas Valley	Reid Gardner	Lenzie / H.A.
Las Vegas Valley	.5 hour	1 hour	.75 hour
Moapa Valley	1 hour	.5 hour	.75 hour
Boulder City	.75 hour	1.5 hours	1.25 hours
St. George/Alamo	2 hours	1.5 hours	1.75 hours
Mesquite	1.5 hours	.75 hour	1 hour
Laughlin	2 hours	3 hours	2.75 hours
Henderson	.75 hour	1.5 hour	1.25 hours

6.9 REQUIRED NOTICE FOR OVERTIME:

SCHEDULED OVERTIME: In scheduling overtime work preceding the employee’s next regular work day (shift), the employee shall be given a notice of no later than thirty (30) minutes prior to the employee’s regularly scheduled quit time. Without this notice, such work will be considered as a call-out. It is understood that overtime, when worked as an extension of a regular shift, does not require such notification.

CANCELING OVERTIME: A minimum of twelve (12) hours notice is required on canceling pre-scheduled overtime. When customer arrangements are involved, the Company must provide twelve (12) hours notice prior to the employee's next normal starting time. When such notice of cancellation of pre-scheduled overtime work is not given in accordance with the above, employees involved will be paid for two (2) hours at the appropriate overtime rate if they report for and are retained for work. When such notice of cancellation is not given in accordance with the above, but employees are later notified of work cancellation, they will be paid for two (2) hours at the appropriate overtime rate. If they report and are not retained for work, they shall receive pay for two (2) hours at the appropriate overtime rate.

108

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION

ALTERNATIVE SHIFT AGREEMENTS

Twelve-Hour Shift Schedule (THS)

The following provisions shall supersede the corresponding articles of the Collective Bargaining Agreement for the purpose of establishing work conditions applicable to those employees assigned to the Twelve-Hour Shift (THS) schedule. All paragraphs not listed below should be considered unchanged from the Collective Bargaining Agreement.

WORKING HOURS AND RATES PAY:

Workday:Twelve (12) consecutive hours per day shall constitute a work shift.  The day shift shall begin at 6:00am; the night shift shall begin at 6:00pm.

Work Week:Four (4) twelve (12) hour shifts (48 hours) and three (3) twelve (12) hour shifts (36 hours) as described in Exhibit V-A, and V-B shall constitute the basic work schedule. 6:01pm Sunday to 6:00pm on the next following Sunday shall constitute the regular workweek.

EXHIBIT V-A     TWELVE-HOUR SHIFT (THS) SCHEDULE

            M T W T F S S                                                           M T W T F S S                                            M T W T F S S                                         M T W T F S S

Crew #1    D D D  -  -  -  N                                                      N N N  -  -  -  -                                             -  -   -   D D D D                                           -  -  -   N N N -

Crew #2    N N N  -  -  -  -                                                       -  -   -  D D D D                                            -  -  -   N N N  -                                           D D D  -  -  - N

Crew #3     -  -  -  D D D D                                                     -  -  -   N N N  -                                             D D D  -  - -  N                                           N N N  -  -  -  -

Crew #4     -  -  -  N N N  -                                                     D D D -  -  -  N                                               N N N   -  -  - -                                           -  -  -  D D D  D

  D = Day Shift                                           6:00am (same day) – 6:00pm (same day)

  N = Night Shift                                6:00pm (preceding day) – 6:00am (same day)

EXHIBIT V-B     TWELVE-HOUR SHIFT (THS) SCHEDULE

            M T W T F S S                                                           M T W T F S S                                            M T W T F S S                                           M T W T F S S

Crew #1    -   -   -  - N N N                                                       N  -  -  - D D D                                              -  N N  N  -  -  -                                           D D D  D -  -  -

Crew #2    N -   -  -  D D D                                                      -  N N N -  -   -                                                D D D  D -  -  -                                           -  -   -  - N N N

Crew #3     D D D D -  -  -                                                       -   -   -  - N N N                                               N  -  -  - D D D                                           -  N N N -  -  -

Crew #4     -  N N N -  -   -                                                      D D D  D -  -  -                                                 -   -  -  - N NN                                           N -  -   -  D D D

  D = Day Shift                                           6:00am (same day) – 6:00pm (same day)

  N = Night Shift                                6:00pm (same day) – 6:00am (following day)

Overtime: Time worked in excess of forty (40) hours within a regular workweek shall be considered overtime and will be paid for at one and one-half (1 ½) times the regular established wage rate except as otherwise provided in this article. In computing overtime, intermission taken out for meals served other than on the job shall be deducted. In computing overtime, any holiday not worked will be considered as twelve (12) hours worked. In scheduling overtime work, a minimum of twelve (12) hours notice, prior to the start of said overtime, but prior to leaving the last shift shall be required; otherwise

109

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

such work will be considered as a callout.  It is understood that this excludes overtime when worked as an extension of a regular shift.

Call-Out: Employees who are called for overtime duty shall receive at least two (2) hours pay, and reasonable travel time to and from home will be considered as time worked for the purpose of satisfying the two-hour minimum cited herein.

Double-Time: Employees who are called for work on an observed holiday or who work anytime during the one (1) day off period, on the last day of the two (2) day off period, the second day of the three (3) day off period, or the fourth day of the seven (7) day off period, shall receive double time for all time worked with an overtime minimum of two (2) hours as provided in Article 6.7. Employees who are called out for overtime work within the eight (8) hour period immediately preceding normal workday\night shall receive double time for all time worked during that period with an overtime minimum as provided above.

Double-Time and One Half / Continuation:  Employees shall be paid at the double time and one half (21/2) rate of pay for all time worked in excess of sixteen (16) hours. Employees who, under the provisions of this clause, would be entitled to pay at the double time and one half rate will not have such right nullified by an interruption of continuous work time of less thansix (6) hours. (Any break in continuous work time of six (6) hours or morewill be considered to be an interruption of continuous work time).

Under the provisions of this article, the employees may be sent home for a specified break and shall not lose any normal time pay for the regular time for the regular time which they are required to lose by reasons of such break.   (It is understood that employees on any such break may be called back to work). Meal periods will not be considered as an interruption of continuous work time and will not be considered as work time except when paid for by the Company. The meal period which, occurs during employees’ regular work hours, will be included in the computation of the break period.

Canceling Overtime: A minimum of twelve (12) hours notice is required on canceling prescheduled overtime, or where customer arrangements are involved, twelve (12) hours notice prior to the employee’s next normal starting time. When such notice of cancellation of prescheduled overtime work is not given in accordance with the above, employees involved will be paid for two (2) hours at established overtime rates if they report and are retained for work.  When such notice of cancellation is not given in accordance with the above, but they are later notified of work cancellation, they will be paid for two (2) hours at time and one-half (1 ½).  If they report and are not retained for work, they shall receive pay for two (2) hours at time and one-half (1 ½).

Multiple Call-Outs: If an employee is called for emergency work more than once in the twenty-four (24) hour period from midnight one day to midnight the following day, minimum overtime compensation shall be paid for two (2) hours only for the first call outside of such employee’s regular work hours on work days, or at any time on his on-work days.  For subsequent calls, minimum overtime compensation shall be paid for one (1) hour and travel time as herein provided. For the purpose of this section, concurrent calls or successive calls without a break in work time shall be considered as a single call.  If by reason of a call, an employee works less than the minimum time and into regular work hours, the minimum overtime provisions will apply into his regular work hours and thereby postpone starting time.

All employees included in special or rotating schedules will receive the following consideration:When an employee is transferred from one schedule of work days or work hours to another schedule provided, the schedule is an established schedule or shift for the employee’s work group. The employee shall not be entitled to overtime compensation for work performed during regular work hours of any day involved in the transfer, provided that (a) employee has been notified of such transfer not less than twenty-four (24) hours in advance of the starting time of the new shift or work period; (b) employee has had a minimum of twelve (12) hours off between shifts or work periods; (c) as a result of such transfer employee has not been required to work more than forty (40) hours at the straight rate in any regular pay period involved; and (d) employee has not been required to work more than one (1) short change in the regular pay period involved, provided, however, that such short change was not the result of a voluntary action on the part of an employee, i.e., calling in sick, taking an unauthorized day

110

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

off for personal reason, etc.  (A short change is defined as a transfer from one schedule to another with but twelve (12) hours off between shifts or work periods).

Meal Times:When working overtime before or after the regular shift, or when called out for work after the completion of their regular shift, or when called out on the employee’s regularly scheduled days off, or holidays, and such work is continuous for one and one-half (1 ½) hours or more, the Company shall provide all meals unless the employee is released before meal time or the employee may choose to receive the allowance. The normal meal times shall be one and one-half (1 ½) hours before the employee’s normal starting time, six (6) hours after the normal starting time, fourteen (14) hours after the normal starting time, and eight (8) hours before the normal starting time; and meals will be provided as close to these times as circumstances of work will permit.

Rest Time: All employees who are required to work emergency overtime within the eight (8) hour period immediately preceding their scheduled starting time shall, after the emergency, be entitled to time off with straight time pay equal to time worked.  This is not applicable to a callout or scheduled overtime of three (3) hours or less immediately preceding the employee’s normal starting time. If an employee is entitled to time off under above, such time off which would normally begin at the start of the regular shift maybe taken during the last part of the regular shift.  An employee shall not be required to work during his rest period provided adequate relief is available, however, should an employee be required to work during this period, he shall receive straight time for all time worked during his rest period in addition to his rest period pay.

Shift Differential: Seven (7) day coverage employees will be paid the shift differential applicable to the shift under which any hours worked may fall. Fixed shift employees will be paid their shift differential for all hours worked on that day.

February 1, 2008 through February 1, 2011 …………$1.02 per hour

Shift premiums shall be payable only for hours actually worked and shall not be payable for non-work time such as holidays, sick leave and vacation.

Holidays: Regular employees and temporary employees with more than six (6) months continuous service who are assigned to the THS schedule may be permitted to take holidays off which fall on their scheduled work days; however, if they are not permitted time off, they shall be paid at the rate of time and one-half (1½) in addition to the holiday pay for the time worked on such day during regular working hours.

Holiday Schedule for the 12 Hour Shift Agreement:

New Year’s Day

Martin Luther King Day

Memorial Day

4th Of July

Labor Day

Veterans Day

Thanksgiving Day

Christmas Day

Banked Holidays: If a regular employee or a temporary employee with more than six (6) months of continuous service is required to work on any day observed as a holiday and agrees in advance of that observed holiday to work for the straight time hour rate of pay rather than the premium rate of pay, then the holiday pay of twelve (12) hours may be traded for 12 hours to be added to that employee’s vacation entitlement for that calendar year.  No more than thirty-six (36) hours may be acquired in this manner.

When a holiday falls on an employee’s regularly scheduled work day, or on an employee’s regularly scheduled day off, the holiday may be observed on another work day within the same pay period which

111

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

maybe in conjunction with the employee’s regularly scheduled days off, or any other day within that pay period.  This accommodation must be by mutual Agreement between the employee and the Company and scheduled as far in advance as possible.  It is understood that if any employee requests that they be excused on the fourth day of their four-day workweek, they will be compensated with twelve (12) hours of straight time pay.  If the holiday falls on an employee’s regularly scheduled day off, or the fourth day of the four-day work week, and no other accommodations are made, the last scheduled, non-overtime work day, immediately preceding the holiday, shall be observed as the holiday for the purpose of this article.

Vacations: An employee’s vacation accrual shall be adjusted for all periods of leave of absence without pay as defined elsewhere in this Agreement by reducing the number of vacation days accrued in direct proportion to the number of days of leave without pay within the employee’s anniversary year.  Such reductions shall be applied to any accrued and unused vacation available in the calendar year the adjustment is made, or when such adjustment exceeds the employee’s available vacation, the excess shall be applied against the employee’s next vacation accrual or the employee’s final paycheck, whichever occurs first.  It is understood that no adjustment to vacation accrual will be made due to use of paid sick leave.

Vacation periods shall normally commence on Monday except for employees whose workweek starts on days of the week other than Monday; the vacation period shall commence with the starting days of their respective workweeks.  However, by prior arrangement with the employee'’ supervisor, an employee shall be allowed vacation in increments of one shift or more on any day of the week, except where prohibited by operations needs or where necessary relief cannot be provided, or where payment of overtime to another employee would be required. If a holiday occurs on a workday during an employee’s vacation, it shall not be counted as one day of vacation.  The employee shall receive straight time pay for the holiday as such.

If an employee assigned to the THS schedule, requests, and is granted vacation on the first, second, or third day of their forty-eight hour work schedule, the employee will have those hours considered as time worked for the purpose of calculating their pay on the fourth day of that work schedule.  It is understood that vacation granted for the entire week (i.e., forty-eight (48) hours) or on the fourth day of the four-day workweek will be paid on a straight time basis.

Upgrade And Overtime Scheduling: The Company may upgrade a qualified employee or utilize a relief employee to provide coverage for a vacant shift due to a scheduled or unscheduled absence provided such situation does not result in overtime for any employee in a lower classification, or may elect not to cover the shift when sufficient qualified personnel are available to perform the required functions safely. If these arrangements cannot be made and it is necessary to work employee overtime the following steps will be followed:

1.  An employee, who is on his or her day off and will have at least twelve (12) hours off between shifts, shall be called to fill the vacant shift in accordance with the overtime list. Scheduled overtime shall be paid in accordance with Article 6.4, Overtime Pay. Callouts for coverage of unscheduled vacancies (i.e. sick leave or family sick leave) shall be paid at double time (2X).

2. The Company may force the person that meets the requirements of step #1 above, to come in and work the shift. Scheduled overtime shall be paid in accordance with Article 6.4, Overtime Pay. Callouts for coverage of unscheduled vacancies (i.e. sick leave or family sick leave) shall be paid at double time (2X).

3. If there is no employee available to accept the overtime offered, the Company  shall offer overtime for a portion of the vacant shift to the qualified employee lowest on the overtime list (if the supervisor determines they can do so safely), provided no employee is required to work beyond sixteen (16) hours. The company may divide the shift among multiple employees to avoid working employees beyond sixteen (16) hours. Scheduled overtime shall be paid in

112

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

accordance with Article 6.4, Overtime Pay. Callouts for coverage of unscheduled vacancies (i.e. sick leave or family sick leave) shall be paid at double time (2X).

4. If the Company is still unable to cover the shift at this time, they may use whatever option they choose, including using a member of Management to cover.

It is the intent of the Company not to work employees assigned to the THS schedule beyond their regularly scheduled work hours, however, all employees shall be expected to respond to overtime assignments as necessary.

It is the intent of the Company not to work employees assigned to the THS schedule beyond 16 hours. However, it may be necessary to work employees past 16 hours when all of the above steps are exhausted and the supervisor determines they can do so safely.

It is understood that Article 7.4 TEMPORARY APPOINTMENTS does not apply to 12-hour shift schedule agreement.

113

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION

ALTERNATIVE SHIFT AGREEMENTS

Four-Ten Hour Shift Schedule

The following provisions shall supersede the corresponding articles of the Collective Bargaining Agreement for the purpose of establishing working conditions applicable to those employees assigned to the four-ten hour shift (4/10) schedule. All paragraphs not listed below should be considered unchanged from the Collective Bargaining Agreement.

WORKING HOURS AND RATES OF PAY:

·   Workday: Ten (10) hours in any one (1) day shall constitute the workday.

·   Work Week: Four (4) consecutive workdays, regularly scheduled between the hours of 12:01 am, Monday, and 12:00 midnight, Sunday, shall constitute the basic work week.  The basic work week of regular day-shift employees shall be from Monday through Friday and reflect a schedule of forty (40 hours of straight time work.

Ten Hour Shift Schedule

   M  T  W  T  F S S       M  T  W  T  F  S  S        M  T  W  T  F  S  S      M   T  W  T  F  S  S

Crew 1    D  D  D  D   -  -  -        D  D  D  D   -   -   -         D  D  D  D   -   -   -       D  D  D  D   -   -   -

   M  T  W  T  F S S       M  T  W  T  F  S  S        M  T  W  T  F  S  S      M   T  W  T  F  S  S

Crew 2     -   D  D  D  D  -  -        -   D  D  D  D  -   -          -  D  D   D  D  -   -        -   D  D   D D  -   -

·   Regular Day-Shift Employees:  Regular day shift employees are those employees who are assigned to shifts, which are established on a Monday through Friday schedule and work a shift, which begins between the hours of 6:00 am and 11:59 am.  When mutually agreed to by the Union and Company, the day shift starting time may be scheduled as early as 5:00am to take advantage of daylight hours.

·   Shift Designations: No shift periods shall start between the hours of 12:01am and 5:59am, unless mutually agreed to by memorandum of understanding between the Company and the Union.  The following designations shall apply:

·   FIRST SHIFT: All ten (10) hour shift periods regularly scheduled to begin at 5:00am, or thereafter but before 12:00 noon shall be designated as first shifts.

·   SECOND SHIFT: All ten (10) hour shift periods regularly scheduled to begin at 12:00 noon or thereafter but before 8:00pm, shall be designated as second shifts.

·   THIRD SHIFT: All ten (10) hour shift periods regularly scheduled to begin at 8:00pm, or thereafter but before 12:01am, shall be designated as third shifts.

·   Shift Premium: An incremental increase for all hours worked outside of the employee’s previous schedule for the first four (4) working days of a newly established permanent, temporary or emergency schedule.

·   Lunch Periods: Supervisors will establish a meal period without pay, approximately five (5) hours after the start of a shift.  Employees who are required to begin their lunch more than one (1) hour before or after the regular start of lunchtime shall be paid during the lunch period at the straight time rate.

Overtime:  In computing overtime, intermission taken out for meals served other than on the job shall be deducted, and any holiday or vacation paid in that pay period will be considered as time worked.

114

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Time And A Half:  Except as otherwise provided in this Article, the following situations shall require payment at one and one-half (1 ½ ) time the regular established wage rate:

§   Time worked in excess of ten (10) hours per day.

§   Time worked in excess of any four (4) scheduled workdays in that workweek.

§   Work scheduled in the three (3) hours immediately preceding the normal starting time.

§   Employees who are scheduled to work on an observed holiday.

§   Employees who are scheduled for overtime and such is canceled per Article 6.9 (Required Notice For Overtime)

Double Time: Except as otherwise provided in this Article, the following situations shall require payment at two (2) times the regular established wage rate:

·   Employees, who are scheduled to work within the first five (5) hours of the eight (8) hour period immediately preceding the normal starting time regardless of the day of the week.

·   Employees who work on the third regular day off, with an overtime minimum as provided in Article 6.7 CALL OUTS

For published scheduled outages only, unless other arrangements are made, any personnel on the Tuesday through Friday shift will be moved, without notification, to a Monday through Thursday shift with no shift premium pay.

Rest Time:  Employees who are required to work overtime within the ten (10) hour period immediately preceding their scheduled starting time on a regular work day, shall be entitled to time off with straight time pay equal to time worked during this time frame. This is not applicable to a call out or scheduled overtime of three (3) hours or less immediately preceding the employee's normal starting time.

Establishing Permanent Schedules: The right to establish working schedules and methods of shift rotation for employees, to assign individuals to schedules and to make changes in schedules, rests with the Company. The Company may schedule employees to work for periods of ten (10) hours per day for a minimum period of four (4) days at other than their regular work hours when additional shifts are required for emergency conditions involving the maintenance of repair of plant or station equipment. Company shall pay overtime compensation for all work performed outside of the regular work hours for the first four (4) work days of any such situations.  After the first four (4) day overtime requirement has been fulfilled, the appropriate shift differential shall apply.  On the fifth (5th) day and thereafter for the duration of any such situation, Company shall pay the straight time rate of pay for work performed on work days during the hours of work established under this section.  If any such situation extends beyond four (4) work weeks, Company and the Union may agree to rotate the assignments of employees thereto, but in such event the overtime compensation herein provided for will not be paid to any employee for more than the first four (4) work day period worked outside of regular work hours.

Meals: Meal Times: When working overtime before or after the regular day, or shift, or when called out for overtime work, and such work is continuous for two (2) hours or more, the Company shall provide all meals unless employees are released before the meal time. The normal unpaid meal times shall be:

·   One and one-half (1 1/2) hours before the employee's normal starting time,

·   Eight (8) hours before the employee's normal starting time,

·   Six (6) hours after the normal starting time, and

·   Two (2) hours after the normal quitting time.

Holidays: It is understood that Employees may, at their discretion, use two (2) hours of vacation time on holidays to ensure a full eighty (80) hour pay period.  When a holiday falls on an employee’s regularly scheduled day off, the last scheduled non-overtime work day immediately preceding the holiday or the non-overtime work day immediately following the holiday shall be observed as the holiday for the purpose of this Article. Notice of the date that the holiday will be observed shall be posted within the work group a minimum of one week prior to the holiday itself.

115

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION

ALTERNATIVE SHIFT AGREEMENTS

Thirty-Six for Forty

The following provisions shall supersede the corresponding articles of the Collective Bargaining Agreement for the purpose of establishing work conditions applicable to those employees assigned to the 36 for 40 shift. All paragraphs not listed below should be considered unchanged from the Collective Bargaining Agreement.

WORKING HOURS AND RATES OF PAY:

Hours of Work: For the purpose of this Agreement, the hours of work will be 6:00am to 6:00pm.

Workday:Twelve (12) hours in any one (1) day shall constitute the workday.

Work Week: Except as provided for part-time employees, the basic work week shall consist of Three (3) consecutive workdays regularly scheduled between the hours of 12:01am Monday, and 12:00 midnight Sunday. This shall constitute the basic work week.  The basic workweek of this shift shall be Friday, Saturday, and Sunday. This will reflect a schedule of forty (40) hours of straight-time work.

Regular Days off: Days off shall be consecutive; however they may not be within the basic work week.

Break Periods:  A fifteen (15) minute relief period shall be provided for all employees during each one-half (1/2) of the shift.  Work conditions permitting, each break period shall be given as near the middle of each one-half (1/2) of the shift as possible. When employees who are assigned to these schedules are held beyond their normal quitting time, they will receive an additional fifteen (15) minute break, as quickly as operationally possible.

Lunch Periods: Three-Twelve (3/12) Employees will have a thirty (30) minute paid lunch period as part of their regular shift.

Overtime:  In computing overtime, intermission taken out for meals served other than on the job shall be deducted, and any holiday or vacation paid in that pay period will be considered as time worked. The 36 for 40 employees will not be available for call-outs or overtime on Thursday Friday and Saturday nights.

Time and a Half:Except as otherwise provided in this Article, the following situations shall require payment as one and one-half (1-1/2) times the regular established wage rate:

■   Time worked in excess of Twelve (12) hours per day.

■   Time worked in excess of any of the Three (3) scheduled workdays.

■   Work scheduled in the three hours immediately preceding the normal starting time.

■   Employees who are scheduled to work an observed holiday.

■   Employees on Three-Twelve (3-12)’s who are scheduled for overtime except as defined in “Double Time.”

■   Employees who are scheduled for overtime and such is canceled per Article 6.9 (Required notice for overtime)

Double Time:  Except as otherwise provided in this article, the following situations shall require payment at two (2) times the regular established wage rate:

■   Employees, who are scheduled to work within the first five (5) hours of the eight (8) hour period immediately proceeding the normal starting time regardless of the day of the week.

■   Employees who work on the first day (Monday) of a scheduled four (4) day off period.

116

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Rest Time: Employees who are required to work overtime within the Eight (8) hour period immediately preceding their scheduled starting time on a regular workday, shall be entitled to time off at the rate of one and one-half (1-1/2) times the actual hours worked. This would create the potential for Twelve (12) hours of rest time. This is not applicable to a call-out or scheduled overtime of three (3) hours or less immediately preceding the Employees normal starting time.

Required Notice For Overtime:

Scheduled Overtime:  In scheduling overtime work, a minimum of Twelve (12) hours notice is required, prior to the start of any overtime for a particular day, and before leaving the work site on a regular workday.  Without this notice, such work will be considered as a call out.  It is understood that overtime, when work as an extension of a regular shift, does not require such notification.

Example:

An employee assigned to a 6:00 am to 6:00 pm shift and is notified to work the

 next day (their day off) at 6:00 am. If notification is given by the end of shift

(6:00 pm), this overtime is scheduled.

Training Exception: The Company may for the purposes of training only, change schedules (Revert back to eight (8) hours – Monday – Friday) when mutually agreed upon by the Union and the Company, without incurring the premium penalties mentioned previously.

Staffing the 36 for 40 Schedule:

·   Volunteers: The Company will solicit volunteers for this schedule

·   A waiting list (in order from the most senior qualified to the least senior qualified) of volunteers will be kept for the 36 for 40 schedule. This list will be used to staff any changes in the personnel.

·   Volunteers will be on a three (3) month commitment to the 3-12 schedule if another volunteer Employee cannot be found.

·   If there are no volunteers, the two (2) lowest in seniority, in that classification, will be assigned to a 4-10 split weekend schedule.

·   Holiday hours will be tracked to ensure everyone has an opportunity to use their Ninety-six (96) hours when rotating between the 4/10 and 36 for 40 shifts.

·   Schedule adjustments will be made to facilitate payroll as needed.

Meals:

Meal Times: When working overtime before or after the regular day, or shift, or when called out for overtime work, and such work is continuous for two (2) hours or more, the Company shall provide all meals unless employees are released before the meal time. The normal unpaid meal times shall be:

·   One and one-half (1 1/2) hours before the employee’s normal starting time,

·   Eight (8) hours before the employee’s normal starting time,

·   Six (6) hours after the normal starting time, and

·   One (1) hour after the normal quitting time.

Meals will be provided as close to these times as circumstances of the work will permit.  Employees may elect to complete their assignment and take their meal period upon completion of their task.  This meal period would be unpaid time unless directed by their supervision to work through their meal period.  This paid lunch period will be limited to one-half (1/2) hour at the appropriate rate of pay.

Holidays:

                                                                                                                New Years Day                                            Labor Day

                                                                                                                Martin Luther King Day                            Veterans Day

                                                                                                                Memorial Day                                           Thanksgiving Day

                                                                                                                4th Of July                                                  Christmas Day

Note: It is understood that the holidays will be worked with the appropriate premium pay.

117

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Floating Birthday/Holiday:  Employees assigned to this schedule do not receive a floating/birthday holiday as they have 96 hours of holiday designated above.

Banked Holidays:  The provision to bank holidays does not apply to individuals assigned to this schedule.

Vacation in Conjunction with a holiday:

When vacation is used in conjunction with their observed holiday, the 36 for 40 employees will not be required to work the holiday.

Note: Vacation hours will be charged against the Employees accrued hours as follows:

FRIDAY                       =           THIRTEEN  (13) HOURS OF VACATION

SATURDAY               =           THIRTEEN  (13) HOURS OF VACATION

SUNDAY                     =           FOURTEEN (14) HOURS OF VACATION

Note: Sick Leave hours will be charged against the Employees accrued hours as follows:

FRIDAY                      =          THIRTEEN  (13) HOURS OF SICK LEAVE

SATURDAY              =          THIRTEEN  (13) HOURS OF SICK LEAVE

SUNDAY                    =           FOURTEEN (14) HOURS OF SICK LEAVE

118

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

 GENERATION

ARTICLE NO. 16

Working Rules

16.1 SAFETY GEAR: Protective safety equipment such as rubber gloves, hose, hoods and blankets shall be used to make as safe as possible any work performed on any equipment having un-insulated energized parts, in addition, hot line tools may be used when applicable.  The safety precautions taken by the crew are the direct responsibility of the foreman in charge.  The Occupational Safety and Health Standards as contained in 1910.269 sub-part “R” of the Occupational Safety and Health Act (OSHA) shall be considered minimum standards for work performed on electrical transmission and distribution equipment.

16.2 TWO MAN CREW: Two (2) competent electrical workers together on the same fixture shall be required when performing work on wires or equipment carrying voltages in excess of 600 volts.  One (1) of them shall serve principally as a standby person to render assistance in case of an accident.  In no case when working in pairs shall they work simultaneously on wires or parts of different phases or polarities.  One qualified employee shall stand by and serve principally as a safety observer to the other person.

16.12 BOILER BLASTING: While performing any assignment in which explosives have been utilized, qualified employees will be paid a $3.50 per hour shift premium in addition to the appropriate rate of pay. Employees working in this capacity will perform all duties in accordance with the NV Energy S.A.F.E. work practice manual, NV Energy Blasting Program & Procedures, and all local, state and federal regulations. The Blaster in Charge rate of pay will be equal to the Lead Control Operator rate of pay.

119

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

EXHIBIT I

GENERATION

JOB CLASSIFICATION DESCRIPTIONS

(Alphabetical)

APPRENTICE EQUIPMENT MECHANIC  (7011)

Assists the equipment mechanic while undergoing training for the Journeyman level. Does such work as tuning motors, adjusting valves and ignitions, cleaning fuel systems and radiators, adjusting clutches, brakes and carburetors, tests compression of oil and fuel pressure.

APPRENTICE ELECTRICAL / INSTRUMENT TECHNICIAL  (7012)

Assists the generation plant electrical/instrument technician while in training for Journeyman. Assists the Journeyman in the installation, maintenance, repair and testing of electrical equipment in a generating station. Renews and calibrates gauges and control devices on control boards; repairs and calibrates transmitters, receivers, and control drives; and does other repair work as directed by Journeyman instrument technicians while learning trouble shooting techniques for electronic, solid state and pneumatic instrument servicing. Will perform additional duties as required by the electrical/instrument technician.

APPRENTICE MECHANICAL TECHNICIAN / MACHINIST  (7035)

Assists the machinist while in training for Journeyman; assists the Journeyman in precision work on any type of machine as well as work on the floor in tearing down, repairing and placing into operation any plant equipment and may be required to perform other duties as assigned.

APPRENTICE MECHANICAL TECHNICIAN / MECHANIC  (7010)

Assists the mechanic while in training for Journeyman; assists the Journeyman in doing general mechanic work associated with installing or repairing any plant equipment, and will be required to work with other journeymen to learn basic rigging, machining and welding, and may be required to perform other duties as assigned.

APPRENTICE MECHANICAL TECHNICIAN / WELDER  (7009)

Assists the welder while in training for Journeyman; assists the Journeyman in performing all types of gas or electrical welding, and may be required to perform other duties as assigned.

ASSISTANT CONTROL OPERATOR  (7062)

Assists the control operator during operational emergencies, startups, shutdowns and fuel changes. The primary function will be the manual and control work involved in the light off and shutdown of boilers, start-up and shutdown of turbines and operational procedures required in changing of fuels. May also be required to operate any or all plant mechanical or electrical equipment as directed. Must be familiar with the trip functions and testing of all equipment and keep records and logs as required. When necessary, will work as part of the maintenance crew during plant shutdowns, or any emergency when necessary, may be required to work in any position in the plant. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

AUXILIARY OPERATOR  (7076)

Assists control operator in all phases of operations. Inspects and operates plant auxiliary equipment and water treatment equipment at water treatment plant. Monitors and reads gauges, meters, and water treatment control panels to make adjustments that ensure equipment is operating properly. Does switching in and out of breakers. Performs good housekeeping as a matter of clean and safe operations. When necessary will work as part of the maintenance crew during shutdowns. Leaves shift upon proper relief and performs other duties as required. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

120

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

BLASTER IN CHARGE

A Blaster in Charge will lead, assist and work with dedicated personnel to ensure safe and efficient operation of all activities related to blasting and boiler de-slagging. The Blaster in Charge will be required to meet all local, state and federal licensing requirements to handle explosives.

BLASTER ASSISTANT

Qualified employees working under the supervision of the Blaster in Charge will transport, handle and utilize explosives to remove boiler slag prior to entry of personnel. The employees working in this capacity will have to first successfully complete the Nevada Power Company Blasting Training Program.

COAL YARD EQUIPMENT OPERATOR  (6161)

Operates and maintains all equipment assigned to the coal yard including dozers, railroad locomotives and cars, shakers, conveyors, separators, feeders and crushers and such other supplemental equipment as may be assigned to the coal yard. Will be required to work intermittently in any other classification when assigned. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

CONTROL OPERATOR  (6118)

Operates the controls of gas, oil or coal fired boilers and auxiliaries such as boiler feed water and other pumps, compressors, condensers, fan motors and all other equipment necessary for the operations of the plant. Clears boilers, generating units and auxiliaries during outages, cooperates with the system dispatcher's relative to load voltage changes, frequency and switch requirements, adjusting controls of generating equipment according to operating conditions and synchronizes the equipment with the system; maintains daily operating log, a record of all dispatcher and trouble calls, and visitors record; maintains in a clean and orderly manner control room, all equipment and panels; informs his relief fully on existing and preceding operating conditions of the plant and system; acts as part of overhaul crew during plant shutdown, or any emergency when necessary, may be required to work in any position in the plant. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

ELECTRICAL/INSTRUMENT TECHNICIAN  (6050)

Performs a wide variety of skilled electrical and instrumentation work in the installation, maintenance, repair and testing of electrical and electronic equipment in a generation facility. Performs a wide variety of precision tests, repairs, calibrations, modifications, maintenance and inputs on numerous electronics, pneumatic and hydraulic systems. Must have thorough knowledge of computer based process and electrical control systems and skill level to troubleshoot and repair these systems. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

GENERATION MATERIALS REPRESENTATIVE  (5272)

Performs sophisticated functions defined by regular applications of equipment and business software systems. Extensive customer interaction and a significant degree of decision-making authority are required. Supports all areas of material acquisition and handling within generation. Performs “Town Runs” as assigned. May be upgraded to “Materials Specialist” as required. Purchases non-stock, one time only items as directed. Will function as the administrator for the Corporate Purchasing Card System within Generation, including maintenance of records, and data entry for the “Paris” system. Process requisition as assigned to support material acquisition within Generation. Performs other related duties as assigned for which the employee is qualified and capable.

LABORATORY TECHNICIAN  (6160)

The laboratory technician is directly responsible for all phases of chemical monitoring on the plant's boiler water, feed water and cooling water systems and implement proper treatment to control corrosion or scale formation in all water pipe systems and to insure steam purity. The laboratory technician must have a thorough knowledge of Zeolite softeners, mixed bed demineralizers, chlorine room, and clarifier operation. Takes monthly inventory of all chemicals and chemical supplies throughout the plant and laboratory and makes analysis standards and plots graphs for control limits on all chemically treated water as directed. Unloads caustic, acid and chlorine and maintains a supply of chemicals inside

121

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

the plant as necessary. The laboratory technician at gas fired plants will calibrate all conductivity meters and replace corrosion coupons and will perform additional duties as required. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

The laboratory technician at a coal-fired plant will sample and perform analysis of coal at that plant. Sampling and analysis include collection of the sample, riffling, pulverizing, and actual burning of the sample in the bomb calorimeter. Analysis of the sample includes determination of the external moisture, internal moisture, percent of ash, BTU's per pound, percent of sulfur and ash fusion. Performs normal housekeeping duties to insure a clean laboratory and recommends chemical supplies and materials to insure an adequately supplied laboratory.

LEAD

In the absence of appropriate supervision and when directed, leads, assists, and works with other departmental personnel to ensure the efficient operation of related activities. May be required to develop schedules, direct work assignments, prepare job related reports, complete other administrative duties, function in a Journeyman capacity, and perform other work as needed. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

LEAD CONTROL OPERATOR  (6094)

In the absence of appropriate supervision and when directed, leads, assists and works with other departmental personnel to ensure the efficient operation of related activities. May be required to develop schedules, direct work assignments, prepare job related reports, complete other administrative duties, function in a Journeyman capacity, i.e. Control Operator, upgrade to management and perform other work as needed. May be required to work any recognized shift. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MAINTENANCE TECHNICIAN  (6181)

Performs a variety of skilled work including operating equipment, insulating, painting, lubricating and carpentry. Will be required to perform any of the above tasks if necessary. May be required to assist or perform work in any lower classification. This includes lubricating coal-conveying equipment such as conveyors, feeders, etc. This is specifically non-mobile coal yard equipment. Will be authorized to operate - vacuum truck, backhoe, water truck, dump truck, and crane. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MAINTENANCE UTILITY TECHNICIAN  (6192)

Does unskilled work as necessary; keeps Journeyman or apprentice supplied with tools, materials, and supplies while assisting with a specific job; cleans working area and equipment. Operates other special equipment including jackhammer as required and drives truck or pickup in performance of duties. A maintenance utility technician shall not displace an apprentice or a Journeyman. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MATERIAL SPECIALIST  (6096)

Performs manual and clerical duties in connection with receiving, storing and issuing supplies, tools, and equipment; unloads and unpacks incoming materials; places, shelves and racks stock of machine, hand and construction tools; measures, counts, cuts, crates, marks and stencils materials, supplies, tools and equipment; keeps the premises clean; drives a car or pickup in local purchases of materials and equipment.

MATERIAL UTILITY TECHNICIAN  (6098)

Performs unskilled and semi-skilled labor as necessary. Keeps warehouse and outside areas clean. May operate forklift for loading and unloading of materials for deliveries. Drives warehouse vehicles for material deliveries and local purchases of material and equipment. Two hours minimum upgrade if material is to be purchased during town run. Must be able to obtain a CDL within 90 days of hire date. May assist Material Specialist in putting away material and loading material for crews. The ratio should not exceed 1 Material Utility Technician for 7 Material Specialists (1:7). A Material Utility Technician shall not displace a Material Specialist.

122

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

MECHANIC SPECIALIST  (6128)

Maintains all types of construction and transportation equipment and accessories. Diagnoses mechanical, hydraulic and electrical problems, makes and recommends repairs. Designs equipment modifications. Constructs and installs parts and similar apparatus, including booms and winches, to accommodate the required changes. Performs pressure and structural welding, operates metal lathes, and other precision machinery, and does other related mechanical work as required. Maintains work and vehicle records as required by the Company. Performs all the duties of an Equipment Mechanic or Equipment Mechanic B or other work as assigned.

MECHANICAL TECHNICIAN / MACHINIST  (6131)

Must be able to do precision work on any type machine as well as actual work on the floor in tearing down, repairing and putting into operation any plant equipment. Will be required to work intermittently in any of the maintenance classifications if necessary. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MECHANICAL TECHNICIAN / MECHANIC  (6146)

Capable of doing general mechanical work attached to installing or repairing any plant equipment, be familiar with work on high pressure boilers and their auxiliaries. Will be required to work intermittently in any of the maintenance classifications if necessary. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

MECHANICAL TECHNICIAN / WELDER  (6129)

Performs all types of high pressure, gas and electrical welding and layout and must have satisfactorily completed welding tests as designed by, and in accordance with, state boiler safety requirements for high pressure vessels operated by the Company. Will be required to work intermittently in any of the maintenance classifications if necessary. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

RELIEF ASSISTANT CONTROL OPERATOR  (7046)

Performs the duties of an assistant control operator as described in this Exhibit I. The relief assistant control operator shall be assigned to any shift other than the usual schedule for purposes of providing relief to, or coverage for an absent assistant control operator. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

RELIEF AUXILIARY OPERATOR  (7069)

Performs the duties of an auxiliary operator as described in this Exhibit I. The relief auxiliary operator shall be assigned to any shift other than the usual schedule for purposes of providing relief to, or coverage for an absent auxiliary operator. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

RELIEF CONTROL OPERATOR  (6102)

Performs the duties of control operator as described in this Exhibit I. The relief control operator shall be assigned to any shift other than the usual schedule for purposes of providing relief to, or coverage for an absent control operator. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

TECHNICAL SPECIALIST  (7077)

Performs PD\PM maintenance. Will receive specialized training to accomplish said duties outside of the standard training provided for other Bargaining Unit Personnel.  This classification will be the last called for overtime within their previous classification. They will receive the current associated Journeyman rate of pay. Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

123

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

TRAINER - POWER DELIVERY  (6103)

Responsible for development, administration and evaluation of Power Delivery's apprenticeship and Mechanical, Electrical and Instrumentation Journeyman classification cross-training and refresher training. Provides classroom and field training for existing mechanical and electrical and instrumentation employees within Power Delivery. Assists with testing as a pre-qualifier for prospective new hires and promotions. Accountable for testing, documenting and providing regular updates to Power Delivery Management and others as required on progress and qualifications of apprentices and Mechanical, Electrical and Instrumentation Journeymen. Will work in conjunction with Power Delivery apprenticeship committee. May be required to work outages if properly trained, and will not displace other Journeyman.

UTILITY OPERATOR (7001)

Assist auxiliary and control operators and employees in other classifications as assigned by their supervisor, in the semiskilled work involved in the operating of generating and auxiliary equipment; receives fuel oil; operates bottom ash disposal equipment , changes burners for fuel change, clears boilers as necessary, works as a part of the maintenance crew during crew during shut down for overhaul, relieves an auxiliary operator when necessary, and be in training for progression and may be required to perform other duties assigned.

124

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

5272	Gen Materials Representative	1	28.73	29.02
6050	Electrical/Instrument Tech	1	40.41	40.81
6059	Lead Electrical Tech	1	44.45	44.89
6060	Lead Maintenance Tech	1	44.45	44.89
6063	Lead Mechanical Tech/Mech	1	44.45	44.89
6064	Lead Laboratory Tech	1	40.37	40.77
6073	Lead Coal Yard Operator	1	41.06	41.47
6161	Coal Yard Equipment Operator	1	37.35	37.72
6094	Lead Control Operator	1	44.45	44.89
6095	Lead Material Specialist GEN	1	35.94	36.30
6096	Material Specialist GEN	1	30.25	30.55
	2nd Six Months	2	31.38	31.69
	3rd Six Months	3	32.67	33.00
6098	Material Utility Technician	1	22.42	22.64
	2nd Six Months	2	23.30	25.53
	3rd Six Months	3	24.14	24.38
6102	Relief Control Operator	1	41.87	42.29
6103	Trainer Power Delivery	1	44.45	44.89
6118	Control Operator	1	39.73	40.13
	2nd Six Months	2	40.89	41.30
6129	Mechanical Tech/Welder	1	40.41	40.81
6131	Mechanical Tech/Machinist	1	40.41	40.81

125

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

6146	Mechanical Tech/Mechanic	1	40.41	40.81
6160	Laboratory Tech	1	32.92	33.25
	2nd Six Months	2	34.13	34.47
	3rd Six Months	3	35.39	35.74
	4th Six Months	4	36.70	37.07
6181	Maintenance Tech	1	26.71	26.98
	2nd Six Months	2	27.60	27.88
	3rd Six Months	3	28.47	28.75
	4th Six Months	4	29.32	29.61
	5th Six Months	5	30.20	30.50
	6th Six Months	6	31.08	31.39
	7th Six Months	7	31.89	32.21
6192	Maintenance Utility Tech	1	16.38	16.54
	2nd Six Months	2	17.27	17.44
	3rd Six Months	3	18.10	18.28
	4th Six Months	4	18.97	19.16
	5th Six Months	5	19.84	20.04
	6th Six Months	6	20.69	20.90
	7th Six Months	7	21.56	21.78
7001	Utility Operator	1	16.38	16.54
	2nd Six Months	2	17.27	17.44
	3rd Six Months	3	18.10	18.28
	4th Six Months	4	18.97	19.16
	5th Six Months	5	19.84	20.04
	6th Six Months	6	20.69	20.90
	7th Six Months	7	21.56	21.78
7009	App Mechanical Tech/Welder	1	29.99	30.29
	2nd Six Months	2	31.22	31.53
	3rd Six Months	3	32.27	32.59
	4th Six Months	4	33.40	33.73
	5th Six Months	5	34.52	34.87
	6th Six Months	6	35.62	35.98
	7th Six Months	7	36.74	37.11

126

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

	8th Six Months	8	37.87	38.25
	9th Six Months	9	40.41	40.81
7010	App Mechanical Tech/Machinist	1	29.99	30.29
	2nd Six Months	2	31.22	31.53
	3rd Six Months	3	32.27	32.59
	4th Six Months	4	33.40	33.73
	5th Six Months	5	34.52	34.87
	6th Six Months	6	35.62	35.98
	7th Six Months	7	36.74	37.11
	8th Six Months	8	37.87	38.25
	9th Six Months	9	40.41	40.81
7011	Apprentice Equipment Mechanic	1	29.99	30.29
	2nd Six Months	2	31.22	31.53
	3rd Six Months	3	32.27	32.59
	4th Six Months	4	33.40	33.73
	5th Six Months	5	34.52	34.87
	6th Six Months	6	35.62	35.98
	7th Six Months	7	36.74	37.11
	8th Six Months	8	37.87	38.25
	9th Six Months	9	40.41	40.81
7012	App Electrical/Inst Technician	1	29.99	30.29
	2nd Six Months	2	31.22	31.53
	3rd Six Months	3	32.27	32.59
	4th Six Months	4	33.40	33.73
	5th Six Months	5	34.52	34.87
	6th Six Months	6	35.62	35.98
	7th Six Months	7	36.74	37.11
	8th Six Months	8	37.87	38.25
	9th Six Months	9	40.41	40.81
7034	App Mechanical Tech/Mechanic	1	29.99	30.29
	2nd Six Months	2	31.22	31.53
	3rd Six Months	3	32.27	32.59
	4th Six Months	4	33.40	33.73
	5th Six Months	5	34.52	34.87

127

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

GENERATION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

	6th Six Months	6	35.62	35.98
	7th Six Months	7	36.74	37.11
	8th Six Months	8	37.87	38.25
	9th Six Months	9	40.41	40.81
7046	Relief Assistant Control Operator	1	37.67	38.05
7062	Assistant Control Operator	1	35.66	36.02
	2nd Six Months	2	36.70	37.07
7069	Relief Auxiliary Operator	1	35.96	36.32
7076	Auxiliary Operator	1	34.08	34.42
	2nd Six Months	2	35.02	35.37
7077	Technical Specialist	1	40.41	40.81

128

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

March 31, 1997

Mr. Jim Anzinger

International Brotherhood of Electrical Workers

Local Union #396 3520 BoulderHighway

Las Vegas, Nevada 89121

OPERATIONS WORKING IN MAINTENANCE AT REID GARDNER

Dear Mr. Anzinger:

This letter will document the Agreement between the International Brotherhood of Electrical Workers, Local #396, and Nevada Power Company relative to the use of Operations working in Maintenance at Reid Gardner. Both the IBEW and the Company agree that it is mutually beneficial to agree to changes that allow operations to work in maintenance and go from 12's to 10's while assisting maintenance with required work. The following are the specifics:

1.   The Company will provide seven (7) days calendar days notice. This will result in no monetary penalty to the Company. If the seven (7) days is not followed, then penalties will be handled as identified in the CBA.

2.   With regard to overtime equalization, operations will be placed in their own classification for the purposes of overtime. This includes control operators, auxiliary operators, and assistant control operators. Operations will also be included on their respective overtime list for weekend coverage as long as it doesn't interfere with the scheduled maintenance work.

3.   The hours that they have in their current OT pool will merely be moved over. This classification will be called after MUT's.

4.   Individuals will first be asked to volunteer. If we receive no volunteers, then we will use reverse seniority. This will be done by seniority by classification by crew.

5.   The time frame/period for pulling employees from operations to maintenance will be throughout the duration of an outage season. This will continue for 90 consecutive days or can be extended if a person volunteers to do so. (There are two outage seasons: January through June and July through December). This will occur for a maximum of 180 days within a twelve-month period.

6.   Upon completion of the assignment, the individual will go back to the original shift with no penalty to the employee and will fall right back into their normal rotation.

7.   In emergency situation, operators could be called back to do operations work.

8.   Operators assigned to Maintenance will be paid shift differential.

The above changes reflect the Company and Union's interest in working together to provide a future for our employees and the ultimate success of the Company.

Very truly yours,

/s/Gloria Banks Weddle

Vice President, Human Resources and Corporate Services

AGREED:

/s/James Anzinger

Business Manager and Financial Secretary

IBEW Local #396

129

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

June 25, 1999

Mr. James Anzinger

International Brotherhood of Electrical Workers

Local Union #396

3520 Boulder Highway

Las Vegas, NV 89121

LETTER OF AGREEMENT:

SEVERANCE ALLOWANCE PLAN

The Company and Union agree that the sale of the generating facilities will not trigger the Severance Allowance Plan. The Severance Allowance Plan will no longer be included in the Generation Collective Bargaining Agreement. The Company will require the buyer to maintain the employment of bargaining unit employees assigned to the plants and require the additional terms and conditions indicated in this settlement.

This Severance Allowance Plan Agreement does not impact the Severance Plan outlined in Article 5.5.

Very truly yours.

/s/Mark Sandoval

Director, Southern Operations

AGREED:

/s/James Anzinger

Business Manager and Financial Secretary

IBEW Local #396

130

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

May 4, 1998

Mr. James Anzinger

International Brotherhood of Electrical Workers, Local Union #396

3520 Boulder Highway

Las Vegas, NV 89121

LETTER OF AGREEMENT

FLEXIBILITY LANGUAGE

This letter is to document the Agreement between the Company and the Union regarding the intent of the flexibility language for positions as stated..

"Employees will perform any and all tasks for which they are properly trained and can competently and safely perform."

This language has beenadded to all generation classifications currently in the contract.

* All training must be formally documented

* OSHA requires certain jobs and functions to be performed and certified every year -these will be defined at a later time

* Refresher courses may be required

* Must be able to perform job safely

This clause allows the Company to offer training to the employees to expand their knowledge. The Company will ask for volunteers first. The interest isin placing training efforts into those individuals who have a desire to take advantage of this training and then put into action what they have learned.

Documentation means bookwork in addition to practical and demonstrated application as well.

Very truly yours,

s/Gloria Banks Weddle

Vice President, Corporate Services

AGREED:

s/James Anzinger

IBEW Local #396

131

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

LETTER OF AGREEMENT FOR

CHARLES LENZIE/HARRY ALLEN COMPLEX

BETWEEN

IBEW LOCAL 396 AND NEVADA POWER COMPANY

This Letter of Agreement is entered into by the International Brotherhood of Electrical Workers Local 396 (Union) and Nevada Power Company (Company), collectively referred to as the Parties, concerning the job descriptions, wages, working hours, contracting conditions and the process of staffing the Charles Lenzie Generating Station (Lenzie) as outlined below.  All terms and conditions of the Collective Bargaining Agreement (CBA) between the company and the union shall be in effect except where specified herein.

Due to location and opportunities for greater response and control, Harry Allen will become a part of the Charles Lenzie Complex and employees of Charles Lenzie Station will support Harry Allen Operations and Maintenance activities.

Lenzie is a 1200 MW Combined Cycle Power Plant which is currently under construction and expected to be operational by summer of 2006.

Due to the technology, and operational and maintenance differences from existing units, this letter of agreement has been created to allow for minimal staffing and greater efficiencies while allowing for greater cross functioning amongst classifications.

Occupational Group

Employees will be placed in a separate tab called Combined Cycle Generation in the CBA.

Wages and Employee Classifications

See Attachment A.

Job Descriptions

See Attachment B.

Working Hours

See Attachment C.

Staffing Process for Filling Vacancies

See Attachment D.

Call Outs

See Attachment E.

132

Contracting Language

See Attachment F.

All other conditions contained in the Local 396 Collective Bargaining Agreement apply unless otherwise defined and addressed in this agreement.  The Company and Union agree that once Lenzie becomes operational, there could become a need to reopen this letter of agreement to discuss work schedules and contracting language, or any other area as mutually agreed to by the Company and the Union.

This Letter of Agreement will become effective upon signature of both parties.

Nevada Power Company International Brotherhood of Electrical

Workers

/s/Mary Jean Snow                                                                           /s/James C. Anzinger

Director, Human Resources                                                                           Business Manager/Financial Secretary

Nevada Power Company                                                                           IBEW Local 396

133

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

ATTACHMENT A -- Wages and Employee Classifications

Production Technician

Lead Production Technician

Combined Cycle Operator

Lead Combined Cycle Operator

Cross-functional skills must be obtained with full training provided.

Initially, employees selected for these positions bring basic skill sets and will require training and on-the-job experience to be trained on the technology.

COMBINED CYCLE GENERATION - WAGES
Job Code	Job Title	Step	09/01/2011 1.5%	1st Pay Period After 02/01/2012 1.0%

6065	Combined Cycle Operator	1		42.11	42.53
	2nd Six Months	2		43.36	43.79
6066	Lead Combined Cycle Operator	1		45.79	46.25
	2nd Six Months	2		47.18	47.65
6067	Production Technician	1		42.11	42.53
	2nd Six Months	2		43.36	43.79
6068	Lead Production Technician	1		45.79	46.25
	2nd Six Months		2	47.18	47.65
6826	Warehouse Technician		1	31.76	32.08
	2nd six months		2	32.96	33.29
	3rd six months		3	34.32	34.66

ATTACHMENT B – Job Descriptions

PRODUCTION TECHNICIAN (6067)

Supports the efficient and cost effective production of electric energy by performing any and all power plant maintenance functions which may include but are not limited to: operating equipment, insulating, painting, lubricating, carpentry; mechanical maintenance and repair or power plant equipment including machining, assembly and disassembly of equipment, investigating and correcting mechanical malfunctions; performing skilled electrical and mechanical work necessary to install, operate and maintain building equipment; perform electrical maintenance including heat tracing, motor replacement, motor overhaul, lighting fixture and lighting circuit maintenance.  Maintain high personnel and equipment safety and environmental compliance standards and practices. Assist in the administration and oversight of contractors of plant maintenance, warehousing activities and building and grounds maintenance.   Assist in the development and defining of overall maintenance policies and procedures. Respond quickly to abnormal plant conditions or requirements. Supplement operations by performing basic operations as trained.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

134

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

COMBINED CYCLE OPERATOR (6065)

Supports the efficient cost effective production of electric energy by operating and controlling power plant equipment. Monitors instrumentation to determine plant conditions.  Performs actions necessary to keep the plant operating within prescribed limits. Respond quickly to abnormal plant conditions or requirements. Operating duties include inspection, preventative maintenance and repairs incidental to the performance of regular duties. Assist in the development and defining of overall operations policies and procedures. Operates and monitors turbines, generators, water treatment equipment and plant auxiliary equipment. Maintain high personnel and equipment safety ad environmental compliance standards and practices. Cooperates with system dispatchers relative to load voltage changes, frequency and switch requirements, adjusting controls of generating equipment accordingly to operating conditions and synchronizes the equipment with the system; maintains daily log, a record of all dispatcher and trouble calls, and visitors records; maintains in a clean and orderly manner control room, all equipment and panels; informs relief fully on existing and preceding operating conditions of the plant and system; acts as part of overhaul crew during plant shutdown, or any emergency when necessary, may be required to perform any function in the plant.  Inspects and operates plant auxiliary equipment.  Must be familiar with trip functions and testing of all equipment as directed.  Supplement maintenance by performing basic maintenance duties as trained.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

LEAD PRODUCTION TECHNICIAN (6068)

In the absence of appropriate supervision and when directed, leads, assists, and works with other departmental personnel to ensure the efficient operations of related activities.  May be required to develop schedules, direct work assignments, prepare job related reports, complete other administrative duties, function in a Journeyman capacity and perform other work as needed.  May supervise contract workers performing work that the bargaining unit typically does.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

LEAD COMBINED CYCLE OPERATOR (6066)

In the absence of appropriate supervision and when directed, leads, assists, and works with other departmental personnel to ensure the efficient operations of related activities.  May be required to develop schedules, direct work assignments, prepare job related reports, complete other administrative duties, function in a Journeyman capacity and perform other work as needed.  May supervise contract workers performing work that the bargaining unit typically does.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

WAREHOUSE TECHNICIAN (6826)

Performs all warehouse inventory functions within the generation facility as required in order to maintain and operate the supply chain warehouse.  These functions include receiving, storing, picking, staging, issuing, returns, transfers, putaways, cycle/inventory counts, shipping, warehouse optimization, stock level review, pickup and delivery of materials.  Unloads and unpacks incoming materials; determines storage requirements and stores materials on shelves, racks or in lay-down yards; picks, stages and issues materials; processes returned materials and items requiring repairable actions; performs warehouse to warehouse and bin to bin material transfers; performs cycle counts and inventory counts; packages material for shipment; measures, counts, cuts, crates; marks and stencils materials, supplies and warehouse locations; keeps the premises clean; drives a car or pickup in local purchases of materials; operates forklifts and various material handling equipment.

ATTACHMENT C – Working Hours

Maintenance

The normal work-week shall be defined as five consecutive eight hour days from Monday through Friday and a shift from Tuesday through Saturday.  The hours shall be from 7 to 3:30 p.m. with a half hour unpaid lunch.

Shifts shall run from M-F and Tu-Sat on eight hour shifts to start.  Other shifts may need to be negotiated as the need arises.

135

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Operations

Operations shall follow a twelve-hour shift schedule with a start time of 6:00 a.m. and end time of 6:00 p.m. and the second shift will be from 6:00 p.m. to 6:00 a.m..  A Lead Combined Cycle Operator will work the day shift when not in a relief capacity.

Operations shall provide 24/7 coverage.

ATTACHMENT D – Staffing Process for filling vacancies

The company shall follow the following process when filling the vacancies:

Positions will be posted with the negotiated job descriptions and associated wages.

The company will establish skill set requirements for the new positions.

Interviews will be conducted for qualified employees.  All things being equal, seniority will prevail.

Selection Criteria will include:

■   Skill set requirements

■   Training completed

■   Ability and flexibility

■   Observed behavior

■   File review for letters of discipline and history

A Bargaining Unit representative will be present during the interview process but shall be a neutral and non-rating member.

Hearing Procedures will be followed as defined in the CBA (Article 7.3 - Hearing Procedures).  Although for the initial staffing of Lenzie Station, the bid hearings option ONLY shall apply.

If the company cannot fill its vacancies from the staff who have bid on the positions, they will be authorized to:

■   Externally recruit for these vacancies

■   Temporarily assign employees from Reid Gardner or Clark to facilitate vacancies until staff can be hired on a regular full time basis using existing contract language

■   Utilize temporary staff to fill vacancies on an interim basis

■   Utilize staff supplied by the contractor on site at Lenzie Station

The lateral transfer policy will not apply for the Lenzie Station staffing process now or in the future because of the specific skill set requirements and specialized job descriptions negotiated.

Article 7.8 (Trial Period) shall apply as defined in the existing CBA.

ATTACHMENT  E – Call out for Harry Allen

Harry Allen callout time shall be a 2-hour minimum due to the proximity of Lenzie to Harry Allen as defined in 6.7.  The Harry Allen section will no longer be applicable.

This change shall be implemented once the official remote start capability has been transferred to Lenzie Station and call outs no longer occur from Clark Station.

ATTACHMENT F – Contracting Work

Lenzie Complex shall have a significant requirement for contract work.

136

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

A bargaining unit employee shall be assigned as oversight on shift when contractors are on sight to perform work that is normally performed by bargaining unit employees as defined in the contract.  This language shall not apply to work that is not normally performed by the bargaining unit.

The company shall endeavor to provide as much notice as possible when contracting is required as well as sufficient notice to the employee that shall function as oversight.

It is understood that the man for man, hour for hour requirement in the CBA can be satisfied within a two week window from the occurrence of contracting without penalty or offense.

137

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Letter of Agreement

Between IBEW 396 and Nevada Power Company

Electric System Control Center Operators

June 26, 2006

This Letter of Agreement is entered into by the International Brotherhood of Electrical Workers Local 396 (Union) and Nevada Power Company (Company), collectively referred to as the Parties, concerning the wages, benefits and other conditions of employment for herein identified incumbent Operator/Dispatcher employees of the Company’s Electric System Control Center in Las Vegas, Nevada.  These employees have been represented by the Union as the Occupational Group “System Control” under a previous Letter of Agreement, and this revised LOA represents key enhancements to the original agreement, addressing such issues as progression, wage rates, classifications and placements within those classifications, and revisions to job tasks (primarily the removal of Balancing and Reliability Functions from Transmission).   This LOA supersedes all previous Letters of Agreement between the Parties concerning the System Control Occupational Group.

DISPATCH

ARTICLE NO. 4

Union Activity

4.3  

CONTRACTING WORK:  In case the Company should contract any type of work customarily performed by the Bargaining unit employees the Company shall before awarding such contract will post such opening in accordance with the CBA if no qualified bidders then the Company may contract and shall notify such contractor that all work to be done shall not be less than the terms & conditions pertaining to hours and wages set forth in this agreement.  Upon such award of the contract, the Company shall notify the Union in 30 days in writing of any and all contracts awarded to such contractor and the nature of the work being performed.  The contractor shall be limited to 90 days however after 75 days the Company shall post the openings and if again there are no qualified bidders then the contractors time maybe extended by a mutual agreement between the Company and the Union.

Alternative Shift Agreements

Twelve Hour Shift Schedule (THS)

The following provisions shall supersede the corresponding articles of the Collective Bargaining Agreement for the purpose of establishing work conditions applicable to those employees assigned to the twelve-hour shift (THS) schedule. All paragraphs not listed below should be considered unchanged from the Collective Bargaining Agreement.

WORKING HOURS AND RATES PAY:

■   Workday: Twelve (12) consecutive hours per day shall constitute a work shift.  The day shift shall begin for Distribution at 5:00am; the night shift shall begin at 5:00pm.  The day shift shall begin for Transmission at 5:30am; the night shift at 5:30pm.

■   Workweek: Four (4) twelve (12) hour shifts (48 hours) and three (3) twelve (12) hour shifts (36 hours) as described in Exhibit V-A shall constitute the basic work schedule. 5:01pm Sunday to 5:00pm (Distribution), 5:31pm Sunday to 5:30pm (Transmission) on the next following Sunday shall constitute the regular workweek.   Schedules and starting time maybe changed by mutual agreement between the Union and the Company.

■   Overtime: Time worked in excess of forty (40) hours within a regular workweek shall be considered overtime and will be paid for at one and one-half (1 ½) times the regular established wage rate except as otherwise provided in this article. In computing overtime, intermission taken out for meals served other than on the job shall be deducted. In computing overtime, any holiday not worked will

138

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

■   be considered as twelve (12) hours worked, as defined in Article 10.3 (Company Holidays). In scheduling overtime work, a minimum of twelve (12) hours notice, prior to the start of said overtime, but prior to leaving the last shift shall be required; otherwise such work will be considered as a callout.  It is understood that this excludes overtime when worked as an extension of a regular shift.  Hours worked in excess of 36 hours on employees’ three day workweek is paid at overtime.

■   Call-Out: Employees who are called for overtime duty shall receive at least two (2) hours pay, and reasonable travel time to and from home will be considered as time worked for the purpose of satisfying the two-hour minimum cited herein.

■   Double Time: Employees who are called out for overtime work within the eight (8) hour period immediately preceding normal workday\night shall receive double time for all time worked during that period with an overtime minimum as provided in Article 6.7.

■ Canceling Overtime: A minimum of twelve (12) hours notice is required on canceling prescheduled overtime, or where customer arrangements are involved, twelve (12) hours notice prior to the employee’s next normal starting time. When such notice of cancellation of prescheduled overtime work is not given in accordance with the above, employees involved will be paid for two (2) hours at established overtime rates if they report and are retained for work.  When such notice of cancellation is not given in accordance with the above, but they are later notified of work cancellation, they will be paid for two (2) hours at time and one-half (1 ½).  If they report and are not retained for work, they shall receive pay for two (2) hours at time and one-half (1 ½).

■   Multiple Call-Outs: If an employee is called for emergency work more than once in the twenty-four (24) hour period from midnight one day to midnight the following day, minimum overtime compensation shall be paid for two (2) hours only for the first call outside of such employee’s regular work hours on work days, or at any time on his on-work days.  For subsequent calls, minimum overtime compensation shall be paid for one (1) hour and travel time as herein provided. For the purpose of this section, concurrent calls or successive calls without a break in work time shall be considered as a single call.  If by reason of a call, an employee works less than the minimum time and into regular work hours, the minimum overtime

Meal Times: When working overtime before or after the regular shift, or when called out for work after the completion of their regular shift, or when called out on the employee’s regularly scheduled days off, or holidays, and such work is continuous for one and one-half (1 ½) hours or more, the Company shall provide all meals unless the employee is released before meal time or the employee may choose to receive the allowance. The normal meal times shall be one and one-half (1 ½) hours before the employee’s normal starting time, six (6) hours after the normal starting time, fourteen (14) hours after the normal starting time, and eight (8) hours before the normal starting time; and meals will be provided as close to these times as circumstances of work will permit.

Rest Time: All employees who are required to work emergency overtime within the eight (8) hour period immediately preceding their scheduled starting time shall, after the emergency, be entitled to time off with straight time pay equal to time worked.  This is not applicable to a callout or scheduled overtime of three (3) hours or less immediately preceding the employee’s normal starting time. If an employee is entitled to time off under above, such time off which would normally begin at the start of the regular shift maybe taken during the last part of the regular shift.  An employee shall not be required to work during his rest period provided adequate relief is available, however, should an employee be required to work during this period, he shall receive straight time for all time worked during his rest period in addition to his rest period pay.

Shift Differential: Seven (7) day coverage employees will be paid the shift differential applicable to the shift under which any hours worked may fall.

February 1, 2011 through January 31, 2013:  $1.02 per hour

Shift premiums shall be payable only for hours actually worked and shall not be payable for non-work time such as holidays, sick leave and vacation.

139

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Holidays: Employees under this agreement shall be granted a front-loaded amount of Holiday hours equal to their annual accrual at the beginning of the payroll year.  These hours can be used by the employees, in the same manner as PTO is utilized, throughout the year with customary supervisory approval.

Upgrade And Overtime Scheduling: System Operators are considered one classification and accordingly will not be upgraded to higher levels except as provided in the Step Progression Article.  The Company may upgrade a qualified employee to provide coverage for a vacant shift as a first choice due to a scheduled or unscheduled absence as long as this upgrade does not constitute overtime for the upgraded employee.  This upgraded employee shall be paid at the rate applicable to the classification being covered for all hours of the coverage assignment. If these arrangements cannot be made and it is necessary to work employee overtime the following steps will be followed:

1.   An employee in the same classification, who is on his or her day off and will have at least twelve (12) hours off between shifts, shall be called to fill the vacant shift in accordance with the overtime list.

2.   If there is no employee willing to accept the overtime offered the employee on shift will be offered, if the supervisor feels they can do so safely, the option of splitting the shift.

3.   The Company may force the person that meets the requirements of step #1 above, to come in and work the shift.

4.   If the Company is still unable to cover the shift at this time, they may use whatever option they choose, including using a member of Management to cover.

It is the intent of the Company not to work employees assigned to the THS schedule beyond their regularly scheduled work hours, however, all employees shall be expected to respond to overtime assignments as necessary.

140

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Twelve Hour Shift (THS) Schedule

Table 1: Transmission Shift Schedules

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

Op 1

T

T

T

D

D

D

D

N

N

N

D

D

D

N

N

N

N

Op 2

D

D

N

N

N

N

T

T

T

T

D

D

D

D

Op 3

D

D

D

D

N

N

N

D

D

D

N

N

N

N

T

T

T

Op 4

N

N

N

D

D

D

N

N

N

N

T

T

T

T

Op 5

N

N

T

T

T

T

D

D

D

D

N

N

N

D

D

D

Table 2: Sub-Transmission Shift Schedules

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

Op 1

N

N

D

D

D

D

D

D

D

D

D

D

D

D

D

D

Op 2

D

D

N

N

N

N

N

N

N

N

N

N

N

N

N

N

Op 3

D

D

D

D

D

D

D

D

D

D

D

D

D

D

Op 4

N

N

N

N

N

N

N

N

N

N

N

N

N

N

141

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Table 3: Distribution Shift Schedules

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

Op 1

N

N

D

D

D

D

D

D

D

N

N

N

N

N

N

N

Op 2

N

N

D

D

D

D

D

D

D

N

N

N

N

N

N

N

Op 3

N

N

D

D

D

D

D

D

D

N

N

N

N

N

N

N

DA 1

N

N

D

D

D

D

D

D

D

N

N

N

N

N

N

N

Op 4

D

D

N

N

N

N

N

N

N

D

D

D

D

D

D

D

Op 5

D

D

N

N

N

N

N

N

N

D

D

D

D

D

D

D

DA 2

D

D

N

N

N

N

N

N

N

D

D

D

D

D

D

D

Op 6

D

D

D

D

D

D

D

N

N

N

N

N

N

N

Op 7

D

D

D

D

D

D

D

N

N

N

N

N

N

N

Op 8

D

D

D

D

D

D

D

N

N

N

N

N

N

N

DA 3

D

D

D

D

D

D

D

N

N

N

N

N

N

N

Op 9

N

N

N

N

N

N

N

D

D

D

D

D

D

D

Op 10

N

N

N

N

N

N

N

D

D

D

D

D

D

D

DA 4

N

N

N

N

N

N

N

D

D

D

D

D

D

D

142

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Ten Hour Shift Schedule

Table 4: Trainer Shift Schedule

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

T

F

S

S

M

T

W

Trainer

D

D

D

D

D

D

D

D

D

D

D

D

D

D

D

D

D

D

143

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Vacation and Sick Leave Articles 10, 11 and 12

For Electric System Control only:

It is understood that the Paid Time Off (PTO) program shall only replace the language in Articles 10, 11, and 12 that refer to benefits that are covered in the Paid Time Off program.  All five classifications of the System Control group will be covered on the MPAT PTO and MPAT Short-term disability program with all provisions.  Practices will be consistent with how they are currently managed.

Note: This replaces all of Article 11, 12 and Article 14.9 in the general contract that refers to benefits that are covered in the Paid Time Off Program (PTO).

Management Responsibilities - Article 15, Sec 15.1

Intended to expand Article 15.1: Due to the inherent nature of operating the System, the management will have increased flexibility to provide necessary support and assistance without violating terms of this agreement.  This flexibility is not intended to replace bargaining unit employees.  Management personnel can include, but is not limited to, Supervisors, Operations Engineers, Transmission and Distribution Administrators, Network Engineers, and ESCC Technical Support (EMS) personnel.

Incumbent Contract Employee - Transmission Operations

The Company currently utilizes a contractor resource to perform System Operator duties associated with Transmission Operations.   The Company will continue to contract these duties and pay wages currently established within the existing Vendor Contract until the current contract employee leaves the service of the Company.  At that time the parties agree that these System Operator duties shall be covered under the Collective Bargaining Agreement.  

144

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

System Operator Progression

Four families of Operator/Dispatcher classifications are established by this Letter of Agreement for the System Control Occupational Group, namely, Dispatch Assistant, Distribution, Transmission, and Trainer.  Progression within families and between families will be as follows,

Progression Within Dispatch Assistant:

Progression within Dispatch Assistant family will be automatic, based on satisfactory performance and minimum time served in each classification (Table 5).  Any Short Term or Long Term Disability leave taken will not be counted towards minimum time required at each classification.

Progression within Distribution:

Progression within Distribution family will be automatic, based on satisfactory performance and minimum time served in each classification (Table 5).  Any Short Term or Long Term Disability leave taken will not be counted towards minimum time required at each classification.

Progression from Distribution to Transmission:

Progression from Distribution Family to Transmission Family will be based on selection for the vacant position in Sub-Transmission classification from the qualified applicants within Senior Distribution classification.  If no Senior Distribution Operators are interested in transfer to Sub-Transmission Operator classification, other classifications within the Distribution Family may be evaluated for transfer to Sub-Transmission classification. The successful candidate(s) advancing to Sub-Transmission classification must agree to the change of work schedule to Transmission Operator THS (Table 1) whenever transfer to a vacancy in Transmission Operator classification is required.

Within initial 24 months at Sub-Transmission classification, Sub-Transmission Operators will be required to attain NERC Certification (Transmission Operator or higher).  In the instance that an employee in the Sub-Transmission classification is unable to attain NERC Certification within 24 months period, the Company, after exhausting all reasonable efforts to train and mentor the employee to attain the Certification, will re-assign the employee to his/her previously held classification within T&D Operations department, for which the Certification is not a requirement.  If, at that time, there are no existing Distribution Operators interested in Sub-Transmission classification, the Company, at its sole discretion, may continue to train the Sub-Transmission Operator beyond the initial 24 month period in the position.

Progression within Transmission:

Progression from Sub-Transmission Classification to Transmission Classification will be based on selection for the vacant position in Transmission classification from the qualified Sub-Transmission Operators.  The Sub-Transmission Operator, with longest length of time as NERC certified operator will be automatically selected for a vacancy in Transmission Operator classification.  A change of schedule from Sub-Transmission schedule (Table 2) to Transmission schedule (Table 1) will be required.

Vacancies in Dispatch Assistant, Distribution, Transmission and Trainer

Vacancies in Dispatch Assistant, Distribution, Transmission, and Trainer families will be filled as follows,

Dispatch Assistant Vacancies:

All vacancies in Dispatch Assistant family will be advertised per existing CBA provisions.  Vacancies in Dispatch Assistant family will be filled at Dispatcher Assistant Start classification.

Distribution Vacancies:

All vacancies in Distribution family will be advertised per existing CBA provisions.  Vacancies in Distribution family will be filled at Distribution Operator Start classification.

145

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

Sub-Transmission Vacancies from Outside T&D Operations:

If no candidates are available from within the Distribution Family to transfer to the Transmission Family, the vacancies in Sub-Transmission classification may be filled externally (Outside T&D Operations) as per provisions of existing CBA.

External candidates coming into Sub-Transmission classification will be required to attain NERC Certification (Transmission Operator or higher) within the initial 24 months.  In the instance that such an employee in the Sub-Transmission classification is unable to attain NERC Certification within the initial 24 months period, the Company, after exhausting all reasonable efforts to train and mentor the employee to attain the Certification, may re-assign the employee to another classification within T&D Operations department, for which the Certification is not a requirement.  If no vacancies exist in other classifications within T&D Operations, the Company may choose to re-assign the employee to another position outside the T&D Operations department.

Transmission Vacancies:

Vacancies in Transmission classification will be filled by automatic selection of the Sub-Transmission Operator, with longest length of time as NERC certified operator.  A change of schedule from Sub-Transmission schedule (Table 2) to Transmission schedule (Table 1) will be required.

Trainer Vacancies:

All vacancies in Trainer family will be advertised per existing CBA provisions.

Closed Classifications

Upon execution of this LOA, the existing classifications of System Dispatcher I, II, III,  and System Operator I, II, III, shall be deleted.  Incumbent Assistant Dispatchers, Distribution Operators, and Transmission Operators shall be placed in the new classifications established in this LOA.

System Control Classifications and Wage Rates

Upon execution of this LOA, the following classifications and wage rates will be in effect for Dispatcher Assistants, Trainer, and System Operators.

Table 5: System Operator Classifications
Family	Job Code	Classification	Step*	09/01/2011  1.5%	1st Pay Period After 02/01/2012 1.0%
Dispatch Assistant	4016	Dispatcher Assistant Start	1 Year	28.87	29.16
	4017	Dispatcher Assistant	1 Year	29.61	29.91
	4018	Senior Dispatcher Assistant		31.62	31.94
Distribution	4019	Operator Start, Distribution	2 Year	43.87	44.31
	4020	Operator, Distribution	2 Year	45.78	46.24
	4021	Senior Operator, Distribution	Vacancy**	48.39	48.87
Transmission	4022	Operator, Sub-Transmission	Vacancy** NERC***	49.09	49.58
	4023	Operator, Transmission		49.96	50.46
Training	4006	Trainer, System Operator		49.96	50.46

146

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

*  Step is defined as time required at each classification level

**  Vacancy in the next higher classification is required for progression

***  NERC Certification is required for progression to Transmission Operator

147

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

System Control Position Descriptions

DISPATCHER ASSISTANT (4017)

Responsible for initial activities relating to power outages and trouble calls.  Monitors and updates the OMS system. May also act as a lead or team member on projects.  Coordinates distribution orders to be dispatched to the Line Troublemen.  Tracks the location of Line Troublemen in order to dispatch them efficiently to their next job.  Timely dispatching of Line Troublemen.  Responsible for answering phones and radios. Maintains and provides system updates.  Facilitates operational functions involving research, notification and follow-ups.  Assist System Dispatchers with operational practices and performs tasks as necessary involving power restoration.  Promotes teamwork.  Develops and maintains effective work relationships by communicating professionally and on a continuous basis.  Informs employee’s relief fully on existing and preceding operating conditions of the system.  Assists System Dispatchers in training of Distribution Dispatch personnel.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

OPERATOR, DISTRIBUTION (4020)

Responsible for continuous, real time, safe, and reliable operation of the distribution system including initial activities relating to power outages and trouble calls. May also act as a lead or team member on projects.  Monitors the OMS system.  Fully capable of assuming the duties of Dispatch Assistant.  Responsible for answering phones and radios.  Maintains and provides system updates. Timely dispatching of Line Troublemen.  Tracks the location and progress of Line Troublemen so dispatched.  Performs research, notification and follow-ups as necessary.  Utilize and update the Outage Management System.  Makes proper notification of system activities as required.  Monitors progress of outages and follows up as necessary.  Research, write, and check switching programs.  Will be required to use independent judgment in order to maintain or restore electric service and will have the direct authority to shed customer load.  Demonstrate ability to operate various systems including but not limited to SCADA, OMS, CADOPS and WMS.  Log and maintain daily log of system events.  Directs field personnel through switching/clearance activities.  Issues Hot Line Permits, Clearances, Intra-Company Releases and Permits to qualified field personnel.  Ensures the accuracy of the distribution mapping system including device and equipment status.  Ensure distribution system integrity by closely monitoring the SCADA system and T & D system status.  Develops contingency plans to help ensure the safe and reliable operation of the distribution system.  Works closely with other departments to resolve loading and customer issues.  Informs employee’s relief fully on existing and preceding operating conditions of the system.   Assists in training of Distribution Dispatch personnel.  Promotes teamwork.  Develops and maintains effective work relationships by communicating professionally and on a continuous basis.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

OPERATOR, SUB-TRANSMISSION (4022)

This real time function is responsible for safe, efficient and reliable operation of the electrical sub-transmission system (primarily 69kV and 138kV) within Nevada Power Company’s control area. May also act as a lead or team member on projects. Works in conjunction with Transmission Operator to ensure power system integrity by continuously monitoring and adjusting as required such items as voltage, power flow, reactive and line loading.  Fully capable of assuming the duties of the Distribution Operator and Dispatch Assistant.  Responsible for and directs switching within substations and on the sub-transmission lines, and issues required clearances and permits while adhering to all NPC Safety rules and procedures. Prepares written switching programs and reviews and approves the switching programs prepared by other Operating personnel.  Will be required to use independent judgment in order to maintain or restore electric service and will have the direct authority to shed customer load.  Adheres to all applicable WECC and NERC policies and NPC transmission system business procedures. Must become NERC-Certified within two years in position.  Completes required training to attain and/or maintain NERC Certification.  Maintains daily logs, prepares and distributes daily reports. Maintains and provides system operations updates as needed.  Employees will perform any and all tasks for which they are properly trained and can competently and safely perform.

148

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

NERC CERTIFICATION REQUIREMENT (SUB-TRANSMISSION CLASSIFICATION) (4022)

The requirement to attain NERC Certification within two years of attaining the Sub-Transmission classification is intended to prepare the incumbent employee for progression to the Transmission classification and to provide reasonable backstop measures to ensure that the system is being operated at all times by a NERC-Certified Operator.  In the instance that an employee in the Sub-Transmission classification is unable to attain NERC Certification within 24 months period, the Company, after exhausting all reasonable efforts to train and mentor the employee to attain the Certification, will re-assign the employee to his/her previously held classification within T&D Operations department, for which Certification is not a requirement.  If, at that time, there are no existing Distribution Operators interested in Sub-Transmission classification, the Company may continue to train the Sub-Transmission Operator beyond the initial 24 month period in the position.

OPERATOR, TRANSMISSION (4023)

This real time function is responsible for safe, efficient and reliable operation of the electrical transmission system (69 kV and above) within Nevada Power Company’s control area. May also act as a lead or team member on projects. Ensures power system integrity by continuously monitoring and adjusting as required such items as voltage, power flow, reactive and line loading. Responsible for and directs switching on the Transmission system and issues required clearances and permits while adhering to all NV Energy Safety rules and procedures. Prepares written switching programs and reviews and approves the switching programs prepared by other Operating personnel.  Will be required to use independent judgment in order to maintain or restore electric service and will have the direct authority to shed customer load.  Performs contingency analysis, and adjusts system parameters as necessary to preserve electric transmission system reliability.  Adheres to all applicable WECC and NERC policies and NV ENERGY transmission system business procedures. Maintains daily logs, prepares and distributes daily reports. Performs additional Transmission Operation duties as required.  Serves as on-the-job trainer and mentor for Sub-Transmission Operators.  Must be NERC-certified.

The System Operators grandfathered at Transmission Operator III level are trained and capable of operating the Reliability Operator functions for Nevada Power Company system.  The operators in this closed classification (Transmission Operator III) may be called upon to assist Reliability Operators when and if needed.

TRAINER, SYSTEM OPERATOR (4006)

Primary responsibility is to conduct system operator training associated with NPC ESCC Transmission and Distribution Operations, including development, updating, record keeping and staying current with training needs. Must hold highest NERC certification. Must maintain qualifications or become a qualified trainer for any applicable Transmission or Distribution Operations courses, including NERC or WECC courses. Performs additional Transmission Operation duties as required.

Other:

All other terms and conditions of the CBA, existing LOA, and any written agreements between the Parties apply.

Agreed to this date by

/s/  Paul Kaleta	/s/  Charles W. Randall
For Company/Date	For Union/Date

149

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

A

ALTERNATIVE, 15, 30,48, 56, 61, 75, 105

ALTERNATIVE SHIFTS, 15, 67, 109, 114, 116, 138,

AMENDMENT, 4, 50, 53

APPLICATION REFERRAL, 10

APPRENTICE, 50, 80, 81, 120

ASSIGNMENT TO AN ESTABLISHED SCHEDULE, 19

B

BANKED HOLIDAYS, 30, 111, 118

BENEFIT, 3, 11, 12, 13, 34, 35, 36, 39, 40, 44, 49

BENEFITS, 8, 9, 10, 11, 12, 24, 29, 33, 34, 35, 36, 38, 40, 41, 42, 43, 44, 45

BI-LINGUAL REPRESENTATIVES, 62

BOARD AND LODGING, 20

BREAK PERIOD, 15, 76, 106, 100, 116

BRIDGED TIME FOR RE-HIRED EMPLOYEES, 24, 32

BULLETIN BOARDS, 7

BUSINESS MANAGEMENT, 6

C

CALL-OUTS, 16, 62, 76, 77, 106, 107, 108, 100, 116, 139

CHANGE, 9, 18, 19, 22, 23, 24, 29, 38, 42, 44, 48, 53, 60, 62, 65, 75, 77, 105, 110, 111, 117, 136, 145, 146

CLASSIFICATION, 3, 9, 10, 11, 15, 23, 24, 35, 48, 51, 52, 57, 59, 64, 65, 69, 81, 107, 112, 117, 120, 129, 134, 140, 145, 146, 149

CLASSIFICATIONS, 4, 8, 10, 16, 48, 61, 73, 77, 102, 107, 131, 132, 134, 138, 144, 145, 146

COMPANY HOLIDAYS, 29, 102

CONSIDERATIONS, 31, 32, 33, 77, 108

CONSTRUCTION, 52, 73, 74, 80, 104

CONTINUITY OF SERVICE, 3

CONTRACTING, 7, 11, 58, 73, 104, 132, 133, 136, 137, 138

CREW, 50, 52, 78, 80, 101, 119, 120, 129

D

DAYS OFF, 17, 19, 21, 29, 32, 46, 51, 59, 61, 67, 75, 76, 105, 106,111, 112, 116, 139

DISABILITY, 4, 29, 32, 33, 34, 35, 36, 37, 43, 44, 56, 62, 144, 145,

DISCIPLINE, 6, 15, 22, 48, 78

DOUBLE TIME,16, 29, 32, 62, 67, 76, 106, 110, 112, 113, 115, 116, 139

E

EARLY RELEASE, 21

ELIGIBILITY, 12, 33, 37, 40, 42, 43, 44, 56, 59, 66

ELIGIBLE EMPLOYEES, 13, 29, 30, 33, 38, 39, 43

EMERGENCY, 4, 16, 19, 27, 37, 48, 60, 75, 80, 107, 110, 111, 115, 139

EMERGENCY OR TEMPORARY SCHEDULES, 19, 20, 105, 114

EMPLOYEE STATUS DESIGNATION, 8

ENERGIZED PANELS, 28

EQUALIZATION, 16, 62, 77, 107, 129

EQUALIZING ASSIGNMENTS, 20

ESTABLISHING PERMANENT SCHEDULES, 17, 115

EXCEPTIONS, 16, 18, 33, 107

EXCLUSIONS, 33, 44

150

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

F

FACILITIES, 22, 26, 27, 28, 48, 52, 73, 74, 130

FAMILY, 37, 39, 46, 47, 48, 65, 112, 113, 145, 146

FIRST SHIFT, 17, 61, 67, 75, 105, 114

FLOATING HOLIDAY, 29, 30, 56

H

HEADQUARTERS, 12, 20, 23, 64, 76, 106

HEALTH AND SAFETY, 28

HEARING PROCEDURES, 23, 136

HOLIDAYS, 16, 17, 29, 30, 56, 67, 102, 107, 111, 115, 117, 118, 139

I

INCLEMENT WEATHER, 27

INJURIES, 36

INTERVIEW, 23, 66, 136

INTRA-DEPARTMENTAL WORK LOCATION CHANGE, 22, 24

INTRODUCTION, 3, 33

J

JOB CODE, 71, 93, 125, 134, 146

JURY DUTY, 46

L

LABOR, 16, 19, 24, 27, 48, 49, 62, 66, 77, 107

LEAD, 45, 51, 64, 69, 80, 101

LEAST SENIOR QUALIFIED, 17, 19, 117

LEAVES, 29, 31, 45

LICENSE, 52, 63

LIGHT DUTY, 32, 34

LUNCH PERIODS, 15, 67, 114, 116

M

MEAL, 20, 60, 67, 76, 106, 109, 115

MEAL PERIODS, 15, 17, 19, 20, 21, 76, 110, 114, 117

MEAL RATES, 21

MEAL TIMES, 111, 117, 139

MEDICAL, 8, 11, 12, 30, 33, 35, 37, 38, 42, 44, 45, 47, 59, 65

MILEAGE, 20, 63, 64

MILEAGE ALLOWANCE, 20

MOVING EXPENSES, 23

MUTUAL INTERESTS, 18, 27

151

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

N

NEW EMPLOYEES, 5, 31

NO QUALIFIED BIDDERS, 23, 138

NON-DISCRIMINATION,3,  4

NOTIFICATION, 10, 11,17, 18, 19, 21, 25, 26, 33, 49, 51, 56, 63, 78, 101, 108, 115, 117

O

OFFICE, 5, 22, 45, 62, 63, 64

OUT OF TOWN WORK, 20

P

PART-TIME, 9, 10, 11, 15, 39, 42, 59, 61, 65, 116

PAY DAYS, 16, 23, 107

PAY PROVISIONS, 16, 23, 107

PICKET, 4

POLICIES, 16, 27, 32, 49, 62, 77, 107, 134

POSTING, 7, 23, 66

POSTING REQUIREMENT, 22

POSTINGS, 22

PREMIUM, 11, 17, 18, 19, 20, 29, 30, 45, 59, 61, 62, 75, 76, 77, 105, 106, 108, 111, 114, 115, 117, 119

PROBATIONARY, 8, 9, 10, 11, 24, 29, 31, 44, 62, 65, 66

PROVISIONS, 3, 4, 6, 10, 16, 19, 21, 22, 23, 25, 27, 29, 30, 32, 33, 34, 35, 36, 40, 42, 43, 45, 48, 49, 51, 53, 56, 64, 65, 73, 102, 104, 107, 110, 139, 145, 146

R

RAIN GEAR, 28

RATE OF PAY AND ROTATION, 20

RATES, 3, 15, 23, 38, 44, 45, 61, 63, 66, 67, 75, 78, 102, 105, 107, 109, 114, 116, 138, 146

RECALL, 10, 11, 32, 45, 56, 57, 73, 104

RECALL RIGHTS, 11

RECOVERING OVERPAYMENTS, 16, 107

RED CIRCLE/GRANDFATHER, 15

REGULAR, 7, 8, 9, 11, 15, 16, 17, 19, 20, 24, 29, 31, 32, 34, 35, 42, 45, 46, 52, 59, 61, 63, 64, 65, 75, 102, 105, 108, 110, 111, 114, 115, 116, 138, 139

REPORTING DEFICIENCIES, 27

REPORTING LOCATION, 64

REST TIME, 16, 17, 32, 67, 77, 107, 111, 115, 117, 139

RETURN TO ORIGINAL OR OTHER SCHEDULE, 18

RETURN TO ORIGINAL SCHEDULE, 20

RIGHT OF ASSIGNMENT, 18, 19

RULE VIOLATIONS, 27

152

NV Energy – IBEW L396

Collective Bargaining Agreement

09/01/2011– 01/31/2013

S

SAFETY, 27, 28, 35, 39, 48, 51, 80, 119

SAFETY COMMITTEE, 27

SAFETY INVESTIGATIONS, 27

SAFETY MEETINGS, 27

SCHEDULE PREFERENCE AGREEMENTS, 18

SCHEDULING, 31, 32, 63, 65, 67, 78, 108, 109, 112,117, 139, 140

SECOND SHIFT, 17, 61, 67, 75, 105, 114, 136

SELECTION CRITERIA, 23, 24, 136

SEMI-ANNUAL INSPECTIONS, 27

SENIORITY, 8, 9, 10, 11, 12, 17, 22, 23, 24, 31, 32, 35, 45, 46, 56, 57, 59, 64, 65, 117, 129, 136

SEVEN DAY COVERAGE, 15, 75, 105

SEVEN-DAY COVERAGE EMPLOYEES, 16

SEVERANCE, 11, 12, 13, 14, 33, 73, 104, 130

SHIFT DIFFERENTIAL, 17, 18, 19, 20, 60, 61, 75, 105, 111, 115, 129, 139

SICK, 10, 17, 19, 30, 32, 33, 34, 35, 36, 45, 47, 56, 62, 111, 112, 113, 139, 144

STAFFING OF SCHEDULES, 17

STRAIGHT TIME PAY, 15, 16, 31, 32, 67, 77, 107, 111, 112, 115, 139

SUBPOENA, 46,

T

TEMPORARY, 8, 9, 10, 11, 19, 20, 23, 34, 39, 40, 42, 44, 45, 51, 52, 56, 57, 75, 80, 136

TEMPORARY EMPLOYEES, 30, 46, 64, 65, 111

THIRD SHIFT, 17, 61, 67, 75, 105, 114

TIME AND A HALF, 60, 62, 67, 76, 102, 106, 115, 116

TOOLS, 51, 80

TRAINING, 9, 10, 12, 18, 35, 36, 45, 46, 50, 52, 60, 65, 80, 131, 134, 136

TRAINING EXCEPTIONS, 18

TRAVEL TIME, 18, 77, 78, 107,108, 110, 139

TRAVEL TIME FOR OUT OF TOWN TRAINING, 18

TRIAL PERIOD, 23, 24, 136

U

UNION BUSINESS, 5, 7, 9, 23, 35

UNION DUES, 5

UNION LEADERSHIP ACCESS, 7

UNION STEWARD BUSINESS, 7

V

VACATION,10, 16, 17, 31, 32, 33, 34, 37, 45, 46, 47, 51, 52, 56, 61, 62, 65, 66, 67, 76, 106, 107, 111, 112, 114, 115, 118, 139, 144

VEHICLE, 52, 63

VOLUNTEERS, 12,17, 19, 49, 56, 57, 65, 117, 129, 131

W

WAGES, 3, 5, 15, 16, 48, 49, 56, 58, 71, 93, 107, 125, 132, 134, 146

WELDING, 51

WORK WEEK, 19, 46, 61, 75, 102, 105, 112, 114, 115, 116

WORKDAY, 16, 18, 29, 32, 33, 59, 67, 102, 107, 109, 110, 112, 114, 116, 117, 138

WORKED HOLIDAYS, 29

153

EX-12.1

EXHIBIT 12.1
NV ENERGY, INC.
RATIOS OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
		Year Ended December 31,
		2011		2010		2009		2008		2007
EARNINGS AS DEFINED:
Net Income		$	163,432	$	226,984	$	182,936	$	208,887	$	197,295
Income tax expense			86,915		113,764		75,451		95,354		87,555
Fixed Charges			343,719		363,773		360,896		335,868		310,876
Capitalized Interest (allowance for
borrowed funds used during construction)			(8,718)		(23,355)		(20,229)		(29,527)		(25,967)
	Total	$	585,348	$	681,166	$	599,054	$	610,582	$	569,759
FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)		$	343,719	$	363,773	$	360,896	$	335,868	$	310,876
	Total	$	343,719	$	363,773	$	360,896	$	335,868	$	310,876
RATIO OF EARNINGS TO FIXED
CHARGES			1.70		1.87		1.66		1.82		1.83

(1) Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represents net income adjusted for income taxes and fixed charges excluding capitalized interest.  “Fixed Charges” represent the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed to be attributable to interest.

EX-12.2

EXHIBIT 12.2
NEVADA POWER COMPANY
RATIOS OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
		Year Ended December 31,
		2011		2010		2009		2008		2007
EARNINGS AS DEFINED:
Net Income		$	132,586	$	185,943	$	134,284	$	151,431	$	165,694
Income tax expense			70,737		91,757		61,652		71,382		78,352
Fixed Charges			233,788		240,830		247,290		210,067		190,836
Capitalized Interest (allowance for
borrowed funds used during construction)			(6,770)		(21,443)		(17,184)		(20,063)		(13,196)
	Total	$	430,341	$	497,087	$	426,042	$	412,817	$	421,686
FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)		$	233,788	$	240,830	$	247,290	$	210,067	$	190,836
	Total	$	233,788	$	240,830	$	247,290	$	210,067	$	190,836
RATIO OF EARNINGS TO FIXED
CHARGES			1.84		2.06		1.72		1.97		2.21

(1) Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represents net income adjusted for income taxes and fixed charges excluding capitalized interest.  “Fixed Charges” represent the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed attributable to interest.

EX-12.3

EXHIBIT 12.3
SIERRA PACIFIC POWER COMPANY
RATIOS OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
		Year Ended December 31,
		2011		2010		2009		2008		2007
EARNINGS AS DEFINED:
Net Income		$	59,886	$	72,375	$	73,085	$	90,582	$	65,667
Income tax expense			31,197		40,404		31,225		37,603		26,009
Fixed Charges			70,418		72,815		74,955		84,478		75,655
Capitalized Interest (allowance for
borrowed funds used during construction)			(1,948)		(1,912)		(3,044)		(9,464)		(12,771)
	Total	$	159,553	$	183,682	$	176,221	$	203,199	$	154,560
FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)		$	70,418	$	72,815	$	74,955	$	84,478	$	75,655
	Total	$	70,418	$	72,815	$	74,955	$	84,478	$	75,655
RATIO OF EARNINGS TO FIXED
CHARGES			2.27		2.52		2.35		2.41		2.04

(1) Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

 For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represent net income adjusted for income taxes and fixed charges excluding capitalized interest.  “Fixed Charges” represent the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed attributable to interest.

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in 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 of our reports dated February 24, 2012, relating to the consolidated financial statements and financial statement schedule of NV Energy, Inc., and the effectiveness of NV Energy, Inc.’s and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of NV Energy, Inc. for the year ended December 31, 2011.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 24, 2012

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-168984-02 on Form S-3ASR of our report dated February 24, 2012, relating to the consolidated financial statements and financial statement schedule of Nevada Power Company appearing in this Annual Report on Form 10-K of Nevada Power Company for the year ended December 31, 2011.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 24, 2012

EX-23.3

EXHIBIT 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-168984-01 on Form S-3ASR of our report dated February 24, 2012, relating to the consolidated financial statements and financial statement schedule of Sierra Pacific Power Company appearing in this Annual Report on Form 10-K of Sierra Pacific Power Company for the year ended December 31, 2011.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 24, 2012

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

I, Michael W. Yackira, certify that:

1.   I have reviewed this annual report on Form 10-K for the year ended December 31, 2011 of NV Energy, Inc.;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 24, 2012

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

NV Energy, Inc.

(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Michael W. Yackira, certify that:

1.   I have reviewed this annual report on Form 10-K for the year ended December 31, 2011 of Nevada Power Company (dba NV Energy);

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 24, 2012

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

Nevada Power Company (dba NV Energy)

(Principal Executive Officer)

EX-31.3

EXHIBIT 31.3

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Michael W. Yackira, certify that:

1.   I have reviewed this annual report on Form 10-K for the year ended December 31, 2011 of Sierra Pacific Power Company (dba NV Energy);

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 24, 2012

/s/ Michael W. Yackira

Michael W. Yackira

Chief Executive Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Executive Officer)

EX-31.4

EXHIBIT 31.4

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

I, Dilek L. Samil, certify that:

1.   I have reviewed this annual report on Form 10-K for the year ended December 31, 2011 of NV Energy, Inc.;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 24, 2012

/s/ Dilek L. Samil

Dilek L. Samil

Chief Financial Officer

NV Energy, Inc.

(Principal Financial Officer)

EX-31.5

EXHIBIT 31.5

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Dilek L. Samil, certify that:

1.   I have reviewed this annual report on Form 10-K for the year ended December 31, 2011 of Nevada Power Company (dba NV Energy);

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 24, 2012

/s/ Dilek L. Samil

Dilek L. Samil

Chief Financial Officer

Nevada Power Company (dba NV Energy)

(Principal Financial Officer)

EX-31.6

EXHIBIT 31.6

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Dilek L. Samil, certify that:

1.   I have reviewed this annual report on Form 10-K for the year ended December 31, 2011 of Sierra Pacific Power Company (dba NV Energy);

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 24, 2012

/s/ Dilek L. Samil

Dilek L. Samil

Chief Financial Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

In connection with this report of NV Energy, Inc. on Form 10-K for the year ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, President and Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.   This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.   The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

NV Energy, Inc.

(Principal Executive Officer)

February 24, 2012

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Nevada Power Company (dba NV Energy) on Form 10-K for the year ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, President and Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.   This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.   The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

Nevada Power Company (dba NV Energy)

(Principal Executive Officer)

February 24, 2012

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.3

EXHIBIT 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Sierra Pacific Power Company (dba NV Energy) on Form 10-K for the year ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.   This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.   The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

Chief Executive Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Executive Officer)

February 24, 2012

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.4

EXHIBIT 32.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

In connection with this report of NV Energy, Inc. on Form 10-K for the year ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof, I, Dilek L. Samil, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.   This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.   The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Dilek L. Samil

Dilek L. Samil

Chief Financial Officer

NV Energy, Inc.

(Principal Financial Officer)

February 24, 2012

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.5

EXHIBIT 32.5

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Nevada Power Company (dba NV Energy) on Form 10-K for the year ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof, I, Dilek L. Samil, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.   This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.   The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Dilek L. Samil

Dilek L. Samil

Chief Financial Officer

Nevada Power Company (dba NV Energy)

(Principal Financial Officer)

February 24, 2012

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.6

EXHIBIT 32.6

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Sierra Pacific Power Company (dba NV Energy) on Form 10-K for the year ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof, I, Dilek L. Samil, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.   This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.   The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Dilek L. Samil

Dilek L. Samil

Chief Financial Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Financial Officer)

February 24, 2012

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

XML

COMMON STOCK AND OTHER PAID-IN CAPITAL (Tables)

12 Months Ended

Dec. 31, 2011

Equity [Abstract]

Dividend Declarations

	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

XML

LONG-TERM DEBT, Debt Instruments (Details) (USD $) In Thousands, unless otherwise specified			12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended			12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended			12 Months Ended			12 Months Ended						12 Months Ended				12 Months Ended				12 Months Ended																				12 Months Ended		12 Months Ended											12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 Secured General And Refunding Mortgage Securities Npc Series [Member]	Dec. 31, 2010 Secured General And Refunding Mortgage Securities Npc Series [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, NPC Series I [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, NPC Series I [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, NPC Series L [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, NPC Series L [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, NPC Series M [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, NPC Series M [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, NPC Series N [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, NPC Series N [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, NPC Series O [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, NPC Series O [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, NPC Series R [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, NPC Series R [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, NPC Series S [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, NPC Series S [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, Series U [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, Series U [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, Series V [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, Series V [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, Series X [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, Series X [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, Series Y [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]	Dec. 31, 2011 Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]	Dec. 31, 2010 Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]	Dec. 31, 2011 Secured Variable Rate Debt Npc Idrb Series 2000 A [Member]	Dec. 31, 2010 Secured Variable Rate Debt Npc Idrb Series 2000 A [Member]	Dec. 31, 2011 Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]	Dec. 31, 2010 Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]	Dec. 31, 2011 Secured Variable Rate Debt Npc Pcrb Series 2006 A [Member]	Dec. 31, 2010 Secured Variable Rate Debt Npc Pcrb Series 2006 A [Member]	Dec. 31, 2011 Secured Variable Rate Debt Sppc Pcrb Series 2006 A [Member]	Dec. 31, 2010 Secured Variable Rate Debt Sppc Pcrb Series 2006 A [Member]	Dec. 31, 2011 Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]	Dec. 31, 2010 Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]	Dec. 31, 2011 Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]	Dec. 31, 2010 Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]	Dec. 31, 2010 Secured Variable Rate Debt, Revolving Credit Facilities [Member]	Dec. 31, 2011 NVE Senior Notes due 2014 [Member]	Dec. 31, 2011 NVE Senior Notes due 2017 [Member]	Dec. 31, 2010 NVE Senior Notes due 2017 [Member]	Dec. 31, 2011 NVE Senior Notes due 2020 [Member]	Dec. 31, 2010 NVE Senior Notes due 2020 [Member]	Dec. 31, 2011 Obligations under capital leases [Member]	Dec. 31, 2010 Obligations under capital leases [Member]	Dec. 31, 2011 NVE [Member]	Dec. 31, 2010 NVE [Member]	Dec. 31, 2010 NVE [Member] NVE Senior Notes due 2012 [Member]	Dec. 31, 2010 NVE [Member] NVE Senior Notes due 2014 [Member]	Dec. 31, 2011 NVE [Member] NVE Senior Notes due 2014 [Member]	Dec. 31, 2010 NVE [Member] NVE Senior Notes due 2017 [Member]	Dec. 31, 2010 NVE [Member] NVE Senior Notes due 2020 [Member]	Dec. 31, 2011 NVE [Member] NVE Senior Notes due 2020 [Member]	Dec. 31, 2011 NPC [Member]	Dec. 31, 2010 NPC [Member]	Dec. 31, 2011 NPC [Member] Secured General And Refunding Mortgage Securities Npc Series [Member]	Dec. 31, 2010 NPC [Member] Secured General And Refunding Mortgage Securities Npc Series [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series I [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series I [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series L [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series L [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series M [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series M [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series N [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series N [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series O [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series O [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series R [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series R [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series S [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, NPC Series S [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, Series U [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, Series U [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, Series V [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, Series V [Member]	Dec. 31, 2010 NPC [Member] Secured, General and Refunding Mortgage Securities, Series X [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, Series X [Member]	Dec. 31, 2011 NPC [Member] Secured, General and Refunding Mortgage Securities, Series Y [Member]	Dec. 31, 2011 NPC [Member] Secured Variable Rate Debt Npc Idrb Series 2000 A [Member]	Dec. 31, 2010 NPC [Member] Secured Variable Rate Debt Npc Idrb Series 2000 A [Member]	Dec. 31, 2011 NPC [Member] Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]	Dec. 31, 2010 NPC [Member] Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]	Dec. 31, 2011 NPC [Member] Secured Variable Rate Debt Npc Pcrb Series 2006 A [Member]	Dec. 31, 2010 NPC [Member] Secured Variable Rate Debt Npc Pcrb Series 2006 A [Member]	Dec. 31, 2011 NPC [Member] Obligations under capital leases [Member]	Dec. 31, 2010 NPC [Member] Obligations under capital leases [Member]	Dec. 31, 2011 SPPC [Member]	Dec. 31, 2010 SPPC [Member]	Dec. 31, 2010 SPPC [Member] Secured, General and Refunding Mortgage Securities, SPPC Series H [Member]	Dec. 31, 2011 SPPC [Member] Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]	Dec. 31, 2010 SPPC [Member] Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]	Dec. 31, 2011 SPPC [Member] Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]	Dec. 31, 2010 SPPC [Member] Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]	Dec. 31, 2011 SPPC [Member] Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]	Dec. 31, 2010 SPPC [Member] Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]	Dec. 31, 2011 SPPC [Member] Secured Variable Rate Debt Sppc Pcrb Series 2006 A [Member]	Dec. 31, 2010 SPPC [Member] Secured Variable Rate Debt Sppc Pcrb Series 2006 A [Member]	Dec. 31, 2011 SPPC [Member] Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]	Dec. 31, 2010 SPPC [Member] Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]	Dec. 31, 2011 SPPC [Member] Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]	Dec. 31, 2010 SPPC [Member] Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]	Dec. 31, 2010 SPPC [Member] Secured Variable Rate Debt, Revolving Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 5,161,462			$ 350,000	$ 130,000	$ 130,000	$ 250,000	$ 250,000	$ 210,000	$ 210,000	$ 370,000	$ 370,000	$ 325,000	$ 325,000	$ 350,000	$ 350,000	$ 500,000	$ 500,000	$ 125,000	$ 125,000	$ 500,000	$ 500,000	$ 250,000	$ 250,000	$ 250,000	$ 450,000	$ 450,000	$ 251,742	$ 251,742	$ 250,000	$ 250,000	$ 98,100	$ 98,100	$ 37,700	$ 37,700	$ 37,975	$ 37,975	$ 58,200	$ 58,200	$ 75,000	$ 75,000	$ 81,475	$ 81,475	$ 15,000	$ 195,000		$ 191,500	$ 315,000	$ 315,000	$ 51,270	$ 55,735	$ 510,000				$ 195,000	$ 191,500	$ 315,000	$ 315,000	$ 3,485,045			$ 350,000	$ 130,000	$ 130,000	$ 250,000	$ 250,000	$ 210,000	$ 210,000	$ 370,000	$ 370,000	$ 325,000	$ 325,000	$ 350,000	$ 350,000	$ 500,000	$ 500,000	$ 125,000	$ 125,000	$ 500,000	$ 500,000	$ 250,000	$ 250,000	$ 250,000	$ 98,100	$ 98,100	$ 37,700	$ 37,700	$ 37,975	$ 37,975	$ 51,270	$ 55,735	$ 1,166,417			$ 450,000	$ 450,000	$ 251,742	$ 251,742	$ 250,000	$ 250,000	$ 58,200	$ 58,200	$ 75,000	$ 75,000	$ 81,475	$ 81,475	$ 15,000
Debt Instrument, Unamortized Discount (Premium), Net	12,546	(2,611)																																																			(1)							25,455	11,748																																(12,909)	(14,358)
Current maturities	(139,985)	(355,929)																																																										(139,985)	(355,929)																																0	0
Total Long-Term Debt	$ 5,008,931	$ 4,924,109																																																										$ 3,319,605	$ 3,221,833																																$ 1,179,326	$ 1,195,775
Stated interest rate (in hundredths)			8.25%		6.50%		5.875%		5.95%		6.65%		6.50%		6.75%		6.50%		7.375%		7.125%		5.375%		5.45%	6.00%		6.75%		5.45%															2.81%	6.75%		6.25%
Maturity date			2011		2012		2015		2016		2036		2018		2037		2018		2014		2019		2040		2041	2016		2037		2013		2020		2036		2032		2031		2036		2036			2014	2017		2020						2012	2014			2020				June 1, 2011																				2040		May 15, 2041											2012

XML

REGULATORY ACTIONS, Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010
Regulatory assets
Remaining Amortization Period	- - - -
Receiving Regulatory Treatment - Earning a Return	$ 357,058	[1]
Receiving Regulatory Treatment - Not Earning a Return	900,239
Pending Regulatory Treatment	144,486
Total regulatory assets	1,401,783		1,506,631
Regulatory liabilities
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return	433,706	[1]
Receiving Regulatory Treatment - Not Earning a Return	17,433
Pending Regulatory Treatment	35,120
Total regulatory liabilities	486,259		428,114
Cost of Removal [Member]
Regulatory liabilities
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return	422,033	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory liabilities	422,033		382,634
Income Taxes Regulatory Liabilty [Member]
Regulatory liabilities
Receiving Regulatory Treatment - Earning a Return		[1]
Pending Regulatory Treatment
Total regulatory liabilities	17,433		19,506
Gain on Property Sales [Member]
Regulatory liabilities
Remaining Amortization Period	2013
Receiving Regulatory Treatment - Earning a Return	4,444	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	32,844	[2]
Total regulatory liabilities	37,288		7,151
Renewable Energy Programs Regulatory Liability [Member]
Regulatory liabilities
Remaining Amortization Period	2012
Receiving Regulatory Treatment - Earning a Return	1,046	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	0
Total regulatory liabilities	1,046		10,234
Other Regulatory Liabilities [Member]
Regulatory liabilities
Remaining Amortization Period	Various thru 2017
Receiving Regulatory Treatment - Earning a Return	6,183	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	2,276
Total regulatory liabilities	8,459		8,589
Loss on Reacquired Debt [Member]
Regulatory assets
Remaining Amortization Period	Term of Related Debt
Receiving Regulatory Treatment - Earning a Return	72,408	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory assets	72,408		84,692
Income Taxes Regulatory Asset [Member]
Regulatory assets
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	251,314
Pending Regulatory Treatment
Total regulatory assets	251,314		257,078
Merger Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2046
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	268,668
Pending Regulatory Treatment
Total regulatory assets	268,668		282,535
Lenzie Generating Station [Member]
Regulatory assets
Remaining Amortization Period	2042
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	67,351
Pending Regulatory Treatment
Total regulatory assets	67,351		77,524
Mohave Generating Station and Deferred Costs [Member]
Regulatory assets
Remaining Amortization Period	2017
Receiving Regulatory Treatment - Earning a Return	9,861	[1]
Receiving Regulatory Treatment - Not Earning a Return	12,654
Pending Regulatory Treatment	1,645	[2]
Total regulatory assets	24,160		25,849
Pinon Pine [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2029
Receiving Regulatory Treatment - Earning a Return	27,377	[1]
Receiving Regulatory Treatment - Not Earning a Return	7,016
Pending Regulatory Treatment
Total regulatory assets	34,393		38,960
Asset Retirement Obligation Costs [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	67,891	[2]
Total regulatory assets	67,891		55,182
Conservation programs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2017
Receiving Regulatory Treatment - Earning a Return	151,035	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	7,412	[2]
Total regulatory assets	158,447		177,515
Energy Efficiency Program Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2013
Receiving Regulatory Treatment - Earning a Return	30,379	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory assets	30,379		30,409
Ely Energy Center [Member]
Regulatory assets
Remaining Amortization Period	2017
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	23,403
Pending Regulatory Treatment	34,563	[2]
Total regulatory assets	57,966
Legacy Meters [Member]
Regulatory assets
Remaining Amortization Period	2013
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	21,777	[2]
Total regulatory assets	21,777
Renewable Energy Programs Regulatory Asset [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	29,592	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory assets	29,592		2,627
Peabody Coal Costs [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	17,899
Pending Regulatory Treatment
Total regulatory assets	17,899		17,738
Deferred Rate Increase [Member]
Regulatory assets
Remaining Amortization Period	2011
Receiving Regulatory Treatment - Earning a Return	12,177	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory assets	12,177		91,678
Risk Management [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	2,426
Pending Regulatory Treatment
Total regulatory assets	2,426		30,726
Other Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2031
Receiving Regulatory Treatment - Earning a Return	24,229	[1]
Receiving Regulatory Treatment - Not Earning a Return	33,852
Pending Regulatory Treatment	11,198	[2]
Total regulatory assets	69,279		64,646
Subtotal - excluding pensions [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	357,058	[1]
Receiving Regulatory Treatment - Not Earning a Return	684,583
Pending Regulatory Treatment	144,486
Pensions [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	215,656
Pending Regulatory Treatment	0
NPC [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	241,149	[1]
Receiving Regulatory Treatment - Not Earning a Return	600,305
Pending Regulatory Treatment	120,063
Total regulatory assets	961,517		1,005,392
Regulatory liabilities
Receiving Regulatory Treatment - Earning a Return	234,064	[1]
Receiving Regulatory Treatment - Not Earning a Return	5,798
Pending Regulatory Treatment	35,089
Total regulatory liabilities	274,951		225,983
NPC [Member] | Cost of Removal [Member]
Regulatory liabilities
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return	232,093	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment
Total regulatory liabilities	232,093		208,795
NPC [Member] | Income Taxes Regulatory Liabilty [Member]
Regulatory liabilities
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	5,798
Pending Regulatory Treatment
Total regulatory liabilities	5,798		6,557
NPC [Member] | Gain on Property Sales [Member]
Regulatory liabilities
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	32,844	[3]
Total regulatory liabilities	32,844		0
NPC [Member] | Renewable Energy Programs Regulatory Liability [Member]
Regulatory liabilities
Remaining Amortization Period	2013
Receiving Regulatory Treatment - Earning a Return	1,046	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory liabilities	1,046		7,797
NPC [Member] | Other Regulatory Liabilities [Member]
Regulatory liabilities
Remaining Amortization Period	2017
Receiving Regulatory Treatment - Earning a Return	925	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	2,245
Total regulatory liabilities	3,170		2,834
NPC [Member] | Loss on Reacquired Debt [Member]
Regulatory assets
Remaining Amortization Period	Term of Related Debt
Receiving Regulatory Treatment - Earning a Return	39,958	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment
Total regulatory assets	39,958		43,765
NPC [Member] | Income Taxes Regulatory Asset [Member]
Regulatory assets
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	178,060
Pending Regulatory Treatment
Total regulatory assets	178,060		174,022
NPC [Member] | Merger Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2044
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	168,212
Pending Regulatory Treatment
Total regulatory assets	168,212		176,974
NPC [Member] | Lenzie Generating Station [Member]
Regulatory assets
Remaining Amortization Period	2042
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	67,351
Pending Regulatory Treatment
Total regulatory assets	67,351		77,524
NPC [Member] | Mohave Generating Station and Deferred Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2017
Receiving Regulatory Treatment - Earning a Return	9,861	[1]
Receiving Regulatory Treatment - Not Earning a Return	12,654
Pending Regulatory Treatment	1,645	[2]
Total regulatory assets	24,160		25,849
NPC [Member] | Asset Retirement Obligation Costs [Member]
Regulatory assets
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	60,797	[2]
Total regulatory assets	60,797		48,970
NPC [Member] | Conservation programs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2017
Receiving Regulatory Treatment - Earning a Return	129,885	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	4,004	[3]
Total regulatory assets	133,889		144,107
NPC [Member] | Energy Efficiency Program Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2013
Receiving Regulatory Treatment - Earning a Return	25,250	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory assets	25,250		24,905
NPC [Member] | Ely Energy Center [Member]
Regulatory assets
Remaining Amortization Period	2017
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	23,403
Pending Regulatory Treatment	22,970	[2]
Total regulatory assets	46,373
NPC [Member] | Legacy Meters [Member]
Regulatory assets
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment	21,777	[2]
Total regulatory assets	21,777
NPC [Member] | Renewable Energy Programs Regulatory Asset [Member]
Regulatory assets
Remaining Amortization Period	2013
Receiving Regulatory Treatment - Earning a Return	10,694	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory assets	10,694
NPC [Member] | Peabody Coal Costs [Member]
Regulatory assets
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	17,899
Pending Regulatory Treatment
Total regulatory assets	17,899		17,738
NPC [Member] | Deferred Rate Increase [Member]
Regulatory assets
Remaining Amortization Period	2011
Receiving Regulatory Treatment - Earning a Return	12,177	[1]
Receiving Regulatory Treatment - Not Earning a Return
Pending Regulatory Treatment
Total regulatory assets	12,177		91,678
NPC [Member] | Risk Management [Member]
Regulatory assets
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return		[1]
Receiving Regulatory Treatment - Not Earning a Return	2,426
Pending Regulatory Treatment
Total regulatory assets	2,426		20,261
NPC [Member] | Other Costs [Member]
Regulatory assets
Remaining Amortization Period	2017
Receiving Regulatory Treatment - Earning a Return	13,324	[1]
Receiving Regulatory Treatment - Not Earning a Return	21,772
Pending Regulatory Treatment	8,870	[2],[3]
Total regulatory assets	43,966		26,189
NPC [Member] | Subtotal - excluding pensions [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	241,149	[1]
Receiving Regulatory Treatment - Not Earning a Return	491,777
Pending Regulatory Treatment	120,063
NPC [Member] | Pensions [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	108,528
Pending Regulatory Treatment	0
SPPC [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	115,909	[1]
Receiving Regulatory Treatment - Not Earning a Return	296,965
Pending Regulatory Treatment	24,423
Total regulatory assets	437,297		496,911
Regulatory liabilities
Receiving Regulatory Treatment - Earning a Return	199,642	[1]
Receiving Regulatory Treatment - Not Earning a Return	11,635
Pending Regulatory Treatment	31
Total regulatory liabilities	211,308		202,131
SPPC [Member] | Cost of Removal [Member]
Regulatory liabilities
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return	189,940	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	0
Total regulatory liabilities	189,940		173,839
SPPC [Member] | Income Taxes Regulatory Liabilty [Member]
Regulatory liabilities
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	11,635
Pending Regulatory Treatment	0
Total regulatory liabilities	11,635		12,949
SPPC [Member] | Gain on Property Sales [Member]
Regulatory liabilities
Remaining Amortization Period	2013
Receiving Regulatory Treatment - Earning a Return	4,444	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	0
Total regulatory liabilities	4,444		7,151
SPPC [Member] | Renewable Energy Programs Regulatory Liability [Member]
Regulatory liabilities
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	0
Total regulatory liabilities	0		2,437
SPPC [Member] | Other Regulatory Liabilities [Member]
Regulatory liabilities
Remaining Amortization Period	Various thru 2043
Receiving Regulatory Treatment - Earning a Return	5,258	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	31	[3]
Total regulatory liabilities	5,289		5,755
SPPC [Member] | Loss on Reacquired Debt [Member]
Regulatory assets
Remaining Amortization Period	Term of Related Debt
Receiving Regulatory Treatment - Earning a Return	32,450	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	0
Total regulatory assets	32,450		40,927
SPPC [Member] | Income Taxes Regulatory Asset [Member]
Regulatory assets
Remaining Amortization Period	Various
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	73,254
Pending Regulatory Treatment	0
Total regulatory assets	73,254		83,056
SPPC [Member] | Merger Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2046
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	100,456
Pending Regulatory Treatment	0
Total regulatory assets	100,456		105,561
SPPC [Member] | Pinon Pine [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2029
Receiving Regulatory Treatment - Earning a Return	27,377	[1]
Receiving Regulatory Treatment - Not Earning a Return	7,016
Pending Regulatory Treatment	0
Total regulatory assets	34,393		38,960
SPPC [Member] | Asset Retirement Obligation Costs [Member]
Regulatory assets
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	7,094	[2]
Total regulatory assets	7,094		6,212
SPPC [Member] | Conservation programs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2013
Receiving Regulatory Treatment - Earning a Return	21,150	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	3,408	[3]
Total regulatory assets	24,558		33,408
SPPC [Member] | Energy Efficiency Program Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2013
Receiving Regulatory Treatment - Earning a Return	5,129	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	0
Total regulatory assets	5,129		5,504
SPPC [Member] | Ely Energy Center [Member]
Regulatory assets
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	11,593	[2]
Total regulatory assets	11,593		0
SPPC [Member] | Renewable Energy Programs Regulatory Asset [Member]
Regulatory assets
Remaining Amortization Period	2013
Receiving Regulatory Treatment - Earning a Return	18,898	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	0
Total regulatory assets	18,898		2,627
SPPC [Member] | Risk Management [Member]
Regulatory assets
Remaining Amortization Period	-
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	0
Pending Regulatory Treatment	0
Total regulatory assets	0		10,465
SPPC [Member] | Other Costs [Member]
Regulatory assets
Remaining Amortization Period	Various thru 2031
Receiving Regulatory Treatment - Earning a Return	10,905	[1]
Receiving Regulatory Treatment - Not Earning a Return	12,080
Pending Regulatory Treatment	2,328	[2],[3]
Total regulatory assets	25,313		38,457
SPPC [Member] | Subtotal - excluding pensions [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	115,909	[1]
Receiving Regulatory Treatment - Not Earning a Return	192,806
Pending Regulatory Treatment	24,423
SPPC [Member] | Pensions [Member]
Regulatory assets
Receiving Regulatory Treatment - Earning a Return	0	[1]
Receiving Regulatory Treatment - Not Earning a Return	104,159
Pending Regulatory Treatment	$ 0

[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

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Plan Obligations, Plan Assets and Funded Status (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Pension Benefits [Member]
Change in Benefit Obligations [Rollforward]
Benefit obligation, January 1	$ 806,034		$ 757,748
Service cost	18,427		18,910		18,837
Interest cost	40,676		42,872		44,145
Plan participants' contributions
Actuarial loss (gain)	18,552		54,890
Benefits paid	42,507		58,002
Plan amendments	577		(10,384)
Special termination benefits	286		0		300
Remeasurement adjustment	0		0
Benefit obligation, December 31	842,045		806,034		757,748
Change in Plan Assets [Rollforward]
Fair value of plan net assets, January 1	729,940		670,794
Actual return on plan assets	78,104		70,838
Employer contributions	41,286		41,698
Plan participants' contributions
Benefits paid	37,850		53,390
Fair value of plan net assets, December 31	811,480		729,940		670,794
Defined Benefit Plan, Funded Status of Plan [Abstract]
Funded status	(30,565)	[1]	(76,094)	[1]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.75%		6.75%
Other Post-Retirement Benefits [Member]
Change in Benefit Obligations [Rollforward]
Benefit obligation, January 1	163,423		154,287
Service cost	2,611		2,466		2,421
Interest cost	8,360		8,736		10,072
Plan participants' contributions	2,325		1,924
Actuarial loss (gain)	(12,525)		9,166
Benefits paid	12,255		12,495
Plan amendments	0		(661)
Special termination benefits	100		0		2,800
Remeasurement adjustment	0		0
Benefit obligation, December 31	152,039		163,423		154,287
Change in Plan Assets [Rollforward]
Fair value of plan net assets, January 1	93,648		93,298
Actual return on plan assets	8,615		10,627
Employer contributions	863		294
Plan participants' contributions	2,325		1,924
Benefits paid	12,255		12,495
Fair value of plan net assets, December 31	93,196		93,648		93,298
Defined Benefit Plan, Funded Status of Plan [Abstract]
Funded status	$ (58,843)	[1]	$ (69,775)	[1]

[1] Amounts recognized as non-current liabilities (accrued retirement benefits) in the consolidated balance sheets as of December 31, 2011 and 2010.

XML

LONG-TERM DEBT, Maturities of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Long-term Debt, by Maturity [Abstract]
2012	$ 134,822	[1]
2013	255,405
2014	323,513
2015	251,039
2016	211,245
Long-term Debt, maturing through 2016	1,176,024
Thereafter	3,985,438
Long-term debt including current maturities	5,161,462
Debt Instrument, Unamortized Discount (Premium), Net	12,546		(2,611)
Total	5,148,916
NVE [Member]
Long-term Debt, by Maturity [Abstract]
2012	0
2013	0
2014	195,000
2015	0
2016	0
Long-term Debt, maturing through 2016	195,000
Thereafter	315,000
Long-term debt including current maturities	510,000
Debt Instrument, Unamortized Discount (Premium), Net			(1)
Total	510,000
NPC [Member]
Long-term Debt, by Maturity [Abstract]
2012	134,822	[1]
2013	5,405
2014	128,513
2015	251,039
2016	211,245
Long-term Debt, maturing through 2016	731,024
Thereafter	2,754,021
Long-term debt including current maturities	3,485,045
Debt Instrument, Unamortized Discount (Premium), Net	25,455		11,748
Total	3,459,590
SPPC [Member]
Long-term Debt, by Maturity [Abstract]
2012	0
2013	250,000
2014	0
2015	0
2016	0
Long-term Debt, maturing through 2016	250,000
Thereafter	916,417
Long-term debt including current maturities	1,166,417
Debt Instrument, Unamortized Discount (Premium), Net	(12,909)		(14,358)
Total	$ 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.

XML

STOCK COMPENSATION PLANS (Performance Awards) (Details)	12 Months Ended
	Dec. 31, 2011
Below 35 Th Percentile [Member]
Performance unit vesting based on performance [Abstract]
Shares vested, percent of grant (in hundredths)	0.00%
At 35 Th Percentile [Member]
Performance unit vesting based on performance [Abstract]
Shares vested, percent of grant (in hundredths)	50.00%
At 50 Th Percentile [Member]
Performance unit vesting based on performance [Abstract]
Shares vested, percent of grant (in hundredths)	100.00%
At 75 Th Percentile [Member]
Performance unit vesting based on performance [Abstract]
Shares vested, percent of grant (in hundredths)	150.00%

XML

SEGMENT INFORMATION (Details2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Assets	$ 11,635,128	$ 11,669,668
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Other Investments	5,901	5,956	5,428
Cash	55,195	9,552	14,359
Deferred charges-other	1,923	18,135	19,808
Assets	$ 63,019	$ 33,643	$ 39,595

XML

LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Schedule of Long-term Debt

			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	$	0	$	0	$	0	$	0	$	350,000	$	0	$	350,000	$	0
		6.50% NPC Series I due 2012		130,000		0		130,000		0		130,000		0		130,000		0
		5.875% NPC Series L due 2015		250,000		0		250,000		0		250,000		0		250,000		0
		5.95% NPC Series M due 2016		210,000		0		210,000		0		210,000		0		210,000		0
		6.65% NPC Series N due 2036		370,000		0		370,000		0		370,000		0		370,000		0
		6.50% NPC Series O due 2018		325,000		0		325,000		0		325,000		0		325,000		0
		6.75% NPC Series R due 2037		350,000		0		350,000		0		350,000		0		350,000		0
		6.50% NPC Series S due 2018		500,000		0		500,000		0		500,000		0		500,000		0
		7.375% NPC Series U due 2014		125,000		0		125,000		0		125,000		0		125,000		0
		7.125% NPC Series V due 2019		500,000		0		500,000		0		500,000		0		500,000		0
		5.375% NPC Series X due 2040		250,000		0		250,000		0		250,000		0		250,000		0
		5.45% NPC Series Y due 2041		250,000		0		250,000		0		0		0		0		0
		6.00% SPPC Series M due 2016		450,000		0		0		450,000		450,000		0		0		450,000
		6.75% SPPC Series P due 2037		251,742		0		0		251,742		251,742		0		0		251,742
		5.45% SPPC Series Q due 2013		250,000		0		0		250,000		250,000		0		0		250,000
	Variable Rate Debt (Secured by
		General and Refunding Mortgage
		Securities)
		NPC IDRB Series 2000A due 2020		98,100		0		98,100		0		98,100		0		98,100		0
		NPC PCRB Series 2006 due 2036		37,700		0		37,700		0		37,700		0		37,700		0
		NPC PCRB Series 2006A due 2032		37,975		0		37,975		0		37,975		0		37,975		0
		SPPC PCRB Series 2006A due 2031		58,200		0		0		58,200		58,200		0		0		58,200
		SPPC PCRB Series 2006B due 2036		75,000		0		0		75,000		75,000		0		0		75,000
		SPPC PCRB Series 2006C due 2036		81,475		0		0		81,475		81,475		0		0		81,475
		Revolving Credit Facilities		0		0		0		0		15,000		0		0		15,000
Senior Notes
		6.75% NVE Senior Notes due 2017		0		0		0		0		191,500		191,500		0		0
		6.25% NVE Senior Notes due 2020		315,000		315,000		0		0		315,000		315,000		0		0
		2.81% NVE Term Loan due 2014		195,000		195,000		0		0		0		0		0		0
Obligations under capital leases				51,270		0		51,270		0		55,735		0		55,735		0
Unamortized bond premium
and discount, net				(12,546)		0		(25,455)		12,909		2,611		1		(11,748)		14,358
Current maturities				(139,985)		0		(139,985)		0		(355,929)		0		(355,929)		0
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

Schedule of Maturities of Long-term Debt [Table Text Block]

	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

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

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

XML

STOCK COMPENSATION PLANS (Restricted Stock Units activity) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Performance Units and Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested shares at beginning of year (in shares)	763,386	765,143	389,681
Shares granted (in shares)	890,252	753,612	895,803
Shares vested (in shares)	(958,750)	(666,856)	(520,341)
Shares forfeited (in shares)	(42,704)	(88,513)	0
Nonvested shares at end of year (in shares)	652,184	763,386	765,143
Nonvested shares at beginning of year, weighted average grant date value (in dollars per share)	$ 11.47	$ 11.73	$ 14.96
Shares granted, weighted average grant date value (in dollars per share)	$ 15.18	$ 11.78	$ 10.90
Shares vested, weighted average grant date value (in dollars per share)	$ 13.40	$ 12.08	$ 12.71
Shares forfeited, weighted average grant date value (in dollars per share)	$ 12.51	$ 11.81	$ 0
Nonvested shares at end of year, weighted average grant date value (in dollars per share)	$ 13.64	$ 11.47	$ 11.73
Fair value of shares issued	$ 5,441,944	$ 0	$ 0
Unrecognized compensation expense at end of year	10,663,208	10,725,573	0
Weighted average remaining vesting period (in years)	1.63	1.65	0
Weighted average grant date fair value	13,514,025.36	8,877,549.36	9,764,252.7
Closing trading price of company stock (in dollars per share)	$ 16.35
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested shares at beginning of year (in shares)	149,779	64,667	32,750
Shares granted (in shares)	267,750	169,000	66,000
Shares vested (in shares)	(123,413)	(75,708)	(33,083)
Shares forfeited (in shares)	(4,906)	(8,180)	(1,000)
Nonvested shares at end of year (in shares)	289,210	149,779	64,667
Nonvested shares at beginning of year, weighted average grant date value (in dollars per share)	$ 11.53	$ 11.41	$ 12.79
Shares granted, weighted average grant date value (in dollars per share)	$ 14.51	$ 11.65	$ 10.94
Shares vested, weighted average grant date value (in dollars per share)	$ 12.76	$ 11.73	$ 11.85
Shares forfeited, weighted average grant date value (in dollars per share)	$ 11.58	$ 11.14	$ 10.91
Nonvested shares at end of year, weighted average grant date value (in dollars per share)	$ 13.77	$ 11.53	$ 11.41
Fair value of shares issued	671,162	0	0
Unrecognized compensation expense at end of year	4,728,581	2,104,393	0
Weighted average remaining vesting period (in years)	2.55	2.14
Weighted average grant date fair value	$ 3,885,052.5	$ 1,968,850	$ 722,040

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Fair Value of Plan Assets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Pension Benefits [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	$ 811,480		$ 729,940
Pension Benefits [Member] | Cash and Cash Equivalents [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	44,226	[1]	29,698	[1]
Pension Benefits [Member] | U S Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	153,435	[2]	141,894	[2]
Pension Benefits [Member] | International Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	110,837		91,631
Pension Benefits [Member] | U S Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	64		59
Pension Benefits [Member] | International Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	842		0
Pension Benefits [Member] | U S Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	438,127	[3]	438,508	[3]
Pension Benefits [Member] | International Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	55,037		40,992
Pension Benefits [Member] | U S Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	(92)		35
Pension Benefits [Member] | International Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | U S Convertible Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		573
Pension Benefits [Member] | Administrative Trust [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	9,004	[4]	(13,450)	[4]
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	279,100		334,842
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	4,795	[1]	0	[1]
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	52,204	[2]	141,917	[2]
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	110,837		91,631
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	64		59
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	842		0
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	98,311	[3]	111,866	[3]
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	3,135		2,784
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	(92)		35
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Convertible Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Administrative Trust [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	9,004	[4]	(13,450)	[4]
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	532,380		395,098
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	39,431	[1]	29,698	[1]
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	101,231	[2]	(23)	[2]
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	339,816	[3]	326,642	[3]
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	51,902		38,208
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Convertible Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		573
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Administrative Trust [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[4]	0	[4]
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[1]	0	[1]
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[2]	0	[2]
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[3]	0	[3]
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Convertible Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Administrative Trust [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[4]	0	[4]
Other Post-Retirement Benefits [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	93,196		93,648
Other Post-Retirement Benefits [Member] | Cash and Cash Equivalents [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	2,861	[1]	2,678	[1]
Other Post-Retirement Benefits [Member] | U S Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	45,048	[2]	50,235	[2]
Other Post-Retirement Benefits [Member] | International Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	2,409		2,397
Other Post-Retirement Benefits [Member] | U S Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	1		2
Other Post-Retirement Benefits [Member] | International Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	18		0
Other Post-Retirement Benefits [Member] | U S Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	41,469	[3]	37,600	[3]
Other Post-Retirement Benefits [Member] | International Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	1,196		1,072
Other Post-Retirement Benefits [Member] | U S Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	(2)		1
Other Post-Retirement Benefits [Member] | International Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | U S Convertible Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		15
Other Post-Retirement Benefits [Member] | Administrative Trust [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	196	[4]	(352)	[4]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	55,811		61,862
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	105	[1]	0	[1]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	42,848	[2]	50,235	[2]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	2,409		2,397
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	1		2
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	18		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	10,168	[3]	9,506	[3]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	68		73
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	(2)		1
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | International Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | U S Convertible Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Administrative Trust [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	196	[4]	(352)	[4]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	37,385		31,786
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	2,756	[1]	2,678	[1]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	2,200	[2]	0	[2]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	31,301	[3]	28,094	[3]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	1,128		999
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | International Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | U S Convertible Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		15
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Administrative Trust [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[4]	0	[4]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[1]	0	[1]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[2]	0	[2]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International Equity Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International Preferred Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0	[3]	0	[3]
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International Fixed Income Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | International Future Contracts [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | U S Convertible Securities [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	0		0
Other Post-Retirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Administrative Trust [Member]
Fair value of plan assets [Abstract]
Fair value of plan assets	$ 0	[4]	$ 0	[4]

[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] 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.

[4] The administrative trust net assets/liabilities are primarily comprised of amounts payable to and from brokers for sold and purchased securities.

XML

Schedule II Consolidated Valuation and Qualifying Accounts (Details) (Provision for Uncollectible Accounts [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at January 1		$ 32,341	$ 32,884
Provision charged to income	15,735	15,551	21,839
Amounts written off, less recoveries	(36,269)	(19,208)	(22,382)
Balance at December 31			32,341
NPC [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at January 1		29,375	30,621
Provision charged to income	13,820	13,147	17,519
Amounts written off, less recoveries	(33,497)	(16,094)	(18,765)
Balance at December 31			29,375
SPPC [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at January 1		2,966	2,262
Provision charged to income	1,915	2,404	4,321
Amounts written off, less recoveries	(2,772)	(3,114)	(3,617)
Balance at December 31			$ 2,966

XML

LONG-TERM DEBT, Financing Transactions (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Financing Transactions [Abstract]
Net proceeds from issuance	$ 579,820,000	$ 985,419,000	$ 1,418,872,000
Secured General And Refunding Mortgage Securities Npc Series [Member]
Financing Transactions [Abstract]
Maturity date	2011
Secured, General and Refunding Mortgage Securities, Series X [Member]
Financing Transactions [Abstract]
Maturity date	2040
Secured, General and Refunding Mortgage Securities, Series Y [Member]
Financing Transactions [Abstract]
Maturity date	2041
NVE Senior Notes due 2014 [Member]
Financing Transactions [Abstract]
Maturity date	2014
NVE Senior Notes due 2017 [Member]
Financing Transactions [Abstract]
Maturity date	2017
NVE Senior Notes due 2020 [Member]
Financing Transactions [Abstract]
Maturity date	2020
NVE [Member] | Term Loan [Member]
Financing Transactions [Abstract]
Issuance date	October 2011
Face amount	195,000,000
Maturity date	October 7, 2014
Effective interest rate (in hundredths)	2.81%
Covenant description	(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
LIBOR rate margin (in hundredths)	2.00%
NVE [Member] | NVE Senior Notes due 2012 [Member]
Financing Transactions [Abstract]
Maturity date		2012
Debt redeemed		63,700,000
Purchase price per $1,000 principal amount of Notes redeemed		1,019.51
NVE [Member] | NVE Senior Notes due 2014 [Member]
Financing Transactions [Abstract]
Maturity date		2014
Debt redeemed		230,000,000
Purchase price per $1,000 principal amount of Notes redeemed		1,028.75
NVE [Member] | NVE Senior Notes due 2017 [Member]
Financing Transactions [Abstract]
Percentage of stated principal amount plus accrued interest at which Notes will be redeemed (in hundredths)	102.25%
Debt redeemed	191,500,000
NVE [Member] | NVE Senior Notes due 2020 [Member]
Financing Transactions [Abstract]
Face amount		315,000,000
Maturity date		2020
Net proceeds from issuance		311,000,000
Proceeds from issuance used to redeem other debt		307,000,000
NPC [Member]
Financing Transactions [Abstract]
Net proceeds from issuance	386,884,000	637,463,000	1,065,338,000
NPC [Member] | Secured General And Refunding Mortgage Securities Npc Series [Member]
Financing Transactions [Abstract]
Maturity date	June 1, 2011
Debt redeemed	350,000,000
NPC [Member] | Secured, General and Refunding Mortgage Securities, Series X [Member]
Financing Transactions [Abstract]
Issuance date		September 2010
Face amount		250,000,000
Maturity date		2040
Net proceeds from issuance		247,000,000
Proceeds from issuance used to redeem other debt		231,000,000
NPC [Member] | Secured, General and Refunding Mortgage Securities, Series Y [Member]
Financing Transactions [Abstract]
Issuance date	May 2011
Face amount	250,000,000
Maturity date	May 15, 2041
Net proceeds from issuance	248,000,000
Proceeds from issuance used to redeem other debt	248,000,000
Notional amount of interest rate swap	250,000,000
Swap transaction settlement date	May 9, 2011
Settlement payment amount	14,900,000
Amortization period of regulatory asset established upon settlement of swap transaction (in years)	30
NPC [Member] | Secured Variable Rate Debt, Revolving Credit Facilities [Member]
Financing Transactions [Abstract]
Debt redeemed		16,000,000
Credit facility maximum borrowing capacity		600,000,000
Credit facility expiration date		April 2013
Credit facility interest rate description		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
Base rate margin (in hundredths)		1.25%
LIBOR rate margin (in hundredths)		2.25%
Maximum percentage of total commitments in effect that limits reduction in availability (in hundredths)		50.00%
Covenant terms		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
NPC [Member] | Fixed Rate, Unsecured Tax Exempt Local Furnishing Bonds [Member]
Financing Transactions [Abstract]
Redemption notice date		October 2010
Debt redeemed		206,000,000
NPC [Member] | Unsecured Tax-Exempt Pollution Control Refunding Revenue Bonds [Member]
Financing Transactions [Abstract]
Redemption notice date		October 2010
Debt redeemed		20,000,000
SPPC [Member]
Financing Transactions [Abstract]
Net proceeds from issuance	(403,000)	37,726,000	353,534,000
SPPC [Member] | Secured, General and Refunding Mortgage Securities, SPPC Series H [Member]
Financing Transactions [Abstract]
Maturity date		2012
Debt redeemed		100,000,000
Purchase price per $1,000 principal amount of Notes redeemed		1,069.61
SPPC [Member] | Secured Variable Rate Debt, Revolving Credit Facilities [Member]
Financing Transactions [Abstract]
Credit facility maximum borrowing capacity		$ 250,000,000
Credit facility expiration date		April 2013
Credit facility interest rate description		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
Base rate margin (in hundredths)		1.25%
LIBOR rate margin (in hundredths)		2.25%
Maximum percentage of total commitments in effect that limits reduction in availability (in hundredths)		50.00%
Covenant terms		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

XML

STOCK COMPENSATION PLANS (Status of nonqualified stock options) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Intrinsic value of options exercised	$ 545,695	$ 146,102	$ 21,120
Income from options exercised	$ 830,771	$ 447,983	$ 64,386
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
NQSO's outstanding at beginning of year	728,688	854,717	1,278,557
Granted (in shares)	0	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	(118,175)	(44,730)	(8,000)
Forfeited (in shares)	(71,063)	(81,299)	(415,840)
NQSO's outstanding at end of year (in shares)	539,450	728,688	854,717
NQSO's outstanding at beginning of year, weighted average exercise price (in dollars per share)	$ 15.50	$ 15.40	$ 15.65
Granted, weighted average exercise price (in dollars per share)	$ 0.00	$ 0.00	$ 0
Exercised, weighted average exercise price (in dollars per share)	$ 10.26	$ 8.83	$ 7.35
Forfeited, weighted average exercise price (in dollars per share)	$ 16.64	$ 18.18	$ 16.31
NQSO's outstanding at end of year, weighted average exercise price (in dollars per share)	$ 16.56	$ 15.50	$ 15.40
Options exercisable at year-end (in shares)	539,450	728,688	717,705
Options exercisable at year-end, weighted average exercise price (in dollars per share)	$ 16.56	$ 15.50	$ 14.84

XML

ASSETS HELD FOR SALE (Details) (USD $)	12 Months Ended				1 Months Ended					1 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 NPC [Member]	Dec. 31, 2010 NPC [Member]	Aug. 31, 2011 NPC [Member] Telecommunication Towers [Member] number	Dec. 31, 2011 SPPC [Member]	Dec. 31, 2010 SPPC [Member]	Dec. 31, 2011 SPPC [Member] Electric Distribution and Generation Assets [Member]	Dec. 31, 2010 SPPC [Member] Electric Distribution and Generation Assets [Member]	May 31, 2010 SPPC [Member] Independence Lake [Member]
Long Lived Assets Held-for-sale [Line Items]
Number of towers sold					37
Long Lived Assets Held-for-sale, Proceeds from Sale					$ 32,000,000			$ 132,000,000		$ 15,000,000
Assets
Utility Plant in Service									196,800,000
Less: Accumulated depreciation	3,184,071,000	3,047,438,000	1,906,617,000	1,828,366,000		1,277,454,000	1,219,072,000		55,800,000
Public Utilities, Property, Plant and Equipment, Net	9,227,073,000	8,929,659,000	6,791,695,000	6,548,810,000		2,435,378,000	2,380,849,000		141,000,000
CWIP	487,427,000	908,579,000	352,541,000	825,079,000		134,886,000	83,500,000		5,200,000
Other Assets Held-for-sale, Current									9,100,000
Assets Held-for-sale, Long Lived	0	155,322,000				0	155,322,000		155,300,000
Liabilities
Deferred Credits and Other Liabilities, Noncurrent									30,700,000
Liabilities Held for Sale	0	30,706,000				0	30,706,000		30,700,000
Gain (Loss) on Sale of Properties, before Applicable Income Taxes										14,700,000
Deferred gain recorded as a regulatory liability										$ 7,100,000
Amortization period (in years)	Various									three

XML

COMMITMENTS AND CONTINGENCIES, Contractual Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	$ 1,307
2013	1,047
2014	933
2015	905
2016	888
Unrecorded Unconditional Purchase Obligation, Due after Five Years	10,484
Unrecorded Unconditional Purchase Obligation	15,564
Purchased Power [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	492
2013	427
2014	416
2015	425
2016	433
Unrecorded Unconditional Purchase Obligation, Due after Five Years	3,081
Unrecorded Unconditional Purchase Obligation	5,274
Purchased Power - Not Commercially Operable [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	75
2013	119
2014	204
2015	239
2016	247
Unrecorded Unconditional Purchase Obligation, Due after Five Years	5,360
Unrecorded Unconditional Purchase Obligation	6,244
Coal & Natural Gas [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	376
2013	187
2014	58
2015	55
2016	39
Unrecorded Unconditional Purchase Obligation, Due after Five Years	119
Unrecorded Unconditional Purchase Obligation	834
Transportation [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	168
2013	217
2014	218
2015	155
2016	146
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,779
Unrecorded Unconditional Purchase Obligation	2,683
Long-Term Service Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	49
2013	21
2014	21
2015	20
2016	17
Unrecorded Unconditional Purchase Obligation, Due after Five Years	71
Unrecorded Unconditional Purchase Obligation	199
Capital Projects [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	129
2013	59
2014	0
2015	0
2016	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	188
Operating Leases [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	18
2013	17
2014	16
2015	11
2016	6
Unrecorded Unconditional Purchase Obligation, Due after Five Years	74
Unrecorded Unconditional Purchase Obligation	142
Non cancelable operating lease rent payments	2.4
NPC [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	944
2013	781
2014	723
2015	712
2016	719
Unrecorded Unconditional Purchase Obligation, Due after Five Years	9,328
Unrecorded Unconditional Purchase Obligation	13,207
NPC [Member] | Purchased Power [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	385
2013	318
2014	297
2015	302
2016	305
Unrecorded Unconditional Purchase Obligation, Due after Five Years	2,152
Unrecorded Unconditional Purchase Obligation	3,759
NPC [Member] | Purchased Power - Not Commercially Operable [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	75
2013	119
2014	204
2015	239
2016	247
Unrecorded Unconditional Purchase Obligation, Due after Five Years	5,360
Unrecorded Unconditional Purchase Obligation	6,244
NPC [Member] | Coal & Natural Gas [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	261
2013	127
2014	39
2015	39
2016	39
Unrecorded Unconditional Purchase Obligation, Due after Five Years	119
Unrecorded Unconditional Purchase Obligation	624
NPC [Member] | Transportation [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	85
2013	138
2014	158
2015	111
2016	111
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,601
Unrecorded Unconditional Purchase Obligation	2,204
Percent responsible for Transmission Use and Capacity Exchange Agreement with Great Basin Transmission (in hundredths)	95.00%
NPC [Member] | Long-Term Service Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	41
2013	16
2014	16
2015	15
2016	12
Unrecorded Unconditional Purchase Obligation, Due after Five Years	55
Unrecorded Unconditional Purchase Obligation	155
NPC [Member] | Capital Projects [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	87
2013	54
2014	0
2015	0
2016	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	141
Percent responsible for Utilities' share in the On Line project (in hundredths)	95.00%
NPC [Member] | Operating Leases [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	10
2013	9
2014	9
2015	6
2016	5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	41
Unrecorded Unconditional Purchase Obligation	80
Non cancelable operating lease rent payments	11.5	13.6	13.8
SPPC [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	431
2013	279
2014	206
2015	191
2016	170
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,156
Unrecorded Unconditional Purchase Obligation	2,433
SPPC [Member] | Purchased Power [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	177
2013	126
2014	119
2015	123
2016	128
Unrecorded Unconditional Purchase Obligation, Due after Five Years	929
Unrecorded Unconditional Purchase Obligation	1,602
SPPC [Member] | Purchased Power - Not Commercially Operable [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	0
2013	0
2014	0
2015	0
2016	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	0
SPPC [Member] | Coal & Natural Gas [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	115
2013	60
2014	19
2015	16
2016	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	210
SPPC [Member] | Transportation [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	83
2013	78
2014	59
2015	44
2016	35
Unrecorded Unconditional Purchase Obligation, Due after Five Years	178
Unrecorded Unconditional Purchase Obligation	477
Percent responsible for Transmission Use and Capacity Exchange Agreement with Great Basin Transmission (in hundredths)	5.00%
SPPC [Member] | Long-Term Service Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	8
2013	5
2014	5
2015	5
2016	5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	16
Unrecorded Unconditional Purchase Obligation	44
SPPC [Member] | Capital Projects [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	42
2013	5
2014	0
2015	0
2016	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	47
Percent responsible for Utilities' share in the On Line project (in hundredths)	5.00%
SPPC [Member] | Operating Leases [Member]
Unrecorded Unconditional Purchase Obligation [Abstract]
2012	6
2013	5
2014	4
2015	3
2016	2
Unrecorded Unconditional Purchase Obligation, Due after Five Years	33
Unrecorded Unconditional Purchase Obligation	53
Non cancelable operating lease rent payments	$ 7.4	$ 14.0	$ 13.9

XML

SEVERANCE PROGRAMS (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Number of Positions Eliminated, Period Percent		5.00%
Other operating expense recorded for severance costs		$ 197
NPC [Member]
Restructuring Cost and Reserve [Line Items]
Other operating expense recorded for severance costs	222	6,700
SPPC [Member]
Restructuring Cost and Reserve [Line Items]
Other operating expense recorded for severance costs	$ 864	$ 6,300

XML

STOCK COMPENSATION PLANS (NQSO Oustanding) (Details) (USD $)	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	4.51
Options Outstanding, Intrinsic Value	$ 659,896
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	$ 659,896
Non-Qualified Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
NQSO's outstanding at end of year, weighted average exercise price (in dollars per share)	$ 16.56	$ 15.50	$ 15.40	$ 15.65
NQSO's outstanding	539,450	728,688	854,717	1,278,557
Options exercisable at year-end, weighted average exercise price (in dollars per share)	$ 16.56	$ 15.50	$ 14.84
Options exercisable at year-end (in shares)	539,450	728,688	717,705
Non-Qualified Stock Options [Member] | Year of Grant 2002 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
NQSO's outstanding at end of year, weighted average exercise price (in dollars per share)	$ 15.58
NQSO's outstanding	34,500
Options Outstanding, Remaining Contractual Life (in years)	<1 year
Options exercisable at year-end, weighted average exercise price (in dollars per share)	$ 15.58
Options exercisable at year-end (in shares)	34,500
Non-Qualified Stock Options [Member] | Year of Grant 2005 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
NQSO's outstanding at end of year, weighted average exercise price (in dollars per share)	$ 10.05
NQSO's outstanding	40,733
Options Outstanding, Remaining Contractual Life (in years)	3.1 years
Options exercisable at year-end, weighted average exercise price (in dollars per share)	$ 10.05
Options exercisable at year-end (in shares)	40,733
Non-Qualified Stock Options [Member] | Year of Grant 2006 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
NQSO's outstanding at end of year, weighted average exercise price (in dollars per share)	$ 13.24
NQSO's outstanding	121,246
Options Outstanding, Remaining Contractual Life (in years)	4.1 years
Options exercisable at year-end, weighted average exercise price (in dollars per share)	$ 13.24
Options exercisable at year-end (in shares)	121,246
Non-Qualified Stock Options [Member] | Year of Grant 2007 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
NQSO's outstanding at end of year, weighted average exercise price (in dollars per share)	$ 18.30
NQSO's outstanding	342,971
Options Outstanding, Remaining Contractual Life (in years)	5.1 -5.8 years
Options exercisable at year-end, weighted average exercise price (in dollars per share)	$ 18.30
Options exercisable at year-end (in shares)	342,971

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Accumulated Other Comprehensive Income and Accumulated Benefit Obligation in Excess of Plan Assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	$ 842,045	$ 806,034
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	813,101	772,846
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	811,480	729,940
Pension Benefits [Member]
Amounts recorded in accumulated other comprehensive income and as regulatory assets for pension plans [Abstract]
Net actuarial (gain)/loss	(238,672)	(263,015)
Prior service (credit)/cost	34,730	24,343
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	203,942	238,672
Regulatory asset for pension plans	(194,936)	(232,717)
Accumulated other comprehensive income, pre-tax, at December 31	9,006	5,955
Amounts to be amortized from regulatory assets for pension plans and accumulated other comprehensive income into net periodic cost [Abstract]
Actuarial (gain)/loss	(13,891)
Prior service (credit)/cost	(2,897)
Other Post-Retirement Benefits [Member]
Amounts recorded in accumulated other comprehensive income and as regulatory assets for pension plans [Abstract]
Net actuarial (gain)/loss	(34,501)	(71,650)
Prior service (credit)/cost	15,141	37,149
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	19,360	34,501
Regulatory asset for pension plans	(19,360)	(34,501)
Accumulated other comprehensive income, pre-tax, at December 31	0	0
Amounts to be amortized from regulatory assets for pension plans and accumulated other comprehensive income into net periodic cost [Abstract]
Actuarial (gain)/loss	(2,924)
Prior service (credit)/cost	$ (3,947)

XML

SEVERANCE PROGRAMS

12 Months Ended

Dec. 31, 2011

Restructuring and Related Activities [Abstract]

SEVERANCE PROGRAMS

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.

XML

REGULATORY ACTIONS, Settled Regulatory Actions (Details) (USD $)	Dec. 31, 2010 GRC [Member]	Dec. 31, 2010 NPC [Member]	Dec. 31, 2011 NPC [Member] Mohave Generating Station [Member]	Dec. 31, 2010 NPC [Member] DEAA [Member]	Dec. 31, 2009 NPC [Member] DEAA [Member]	Dec. 31, 2010 NPC [Member] GRC [Member]	Dec. 31, 2008 NPC [Member] GRC [Member]	Dec. 31, 2009 SPPC [Member] DEAA [Member]	Dec. 31, 2010 SPPC [Member] SPPC Gas [Member] DEAA [Member]	Dec. 31, 2009 SPPC [Member] SPPC Gas [Member] DEAA [Member]	Dec. 31, 2010 SPPC [Member] SPPC Electric [Member] DEAA [Member]	Dec. 31, 2009 SPPC [Member] SPPC Electric [Member] DEAA [Member]
Settled Regulatory Actions [Abstract]
DEAA rate (in dollars per kWh)					$ 0.00
Accepted increase (decrease) in general rates						9,200,000			8,300,000		47,000,000	30,800,000
Authorized rate increase (decrease) percentage (in hundredths)	0.41%								4.69%		6.31%	3.19%
Requested rate increase (decrease)					72,100,000					8,700,000		25,900,000
Requested rate increase (decrease) percentage (in hundredths)					3.18%			2.69%		4.71%
Deferred costs refund requested		102,000,000			77,500,000				17,000,000	8,700,000	101,000,000	19,800,000
Amount Of Over Collection Against Deferred Btgr Debit Balance				102,000,000
REPR Revenue Decrease					4,600,000
REPR Revenue Decrease Rate					0.20%
Deferred Base Tariff General Rate balance						95,800,000
Part I Rate Increase							3.00%
GRC Increase Difference Between Billings							9.80%
Mohave Generating Station [Abstract]
Percentage ownership (in hundredths)			14.00%
Mohave Regulatory Asset			12,200,000
Mohave Costs Approved			$ 12,700,000

XML

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

		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

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

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Components of Net Periodic Cost and Expected Benefit Payments (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Average percentage of net periodic costs capitalized [Abstract]
Average percentage of net periodic costs capitalized (in hundredths)	33.40%		34.00%
Pension Benefits [Member]
Net periodic benefit cost [Abstract]
Service cost	$ 18,427	$ 18,910	$ 18,837
Interest cost	40,676	42,872	44,145
Expected return on plan assets	48,767	44,275	37,159
Amortization of:
Prior service (credit)/cost	(2,952)	(1,794)	(1,794)
Actuarial (gain)/loss	(16,620)	(15,106)	(27,575)
Remeasurement adjustment
Total net benefit cost	24,004	30,819	51,604
Special termination benefits excluded from net periodic cost	286	0	300
Other Post-Retirement Benefits [Member]
Net periodic benefit cost [Abstract]
Service cost	2,611	2,466	2,421
Interest cost	8,360	8,736	10,072
Expected return on plan assets	6,386	6,223	6,048
Amortization of:
Prior service (credit)/cost	(3,947)	(3,890)	(1,466)
Actuarial (gain)/loss	(4,333)	(4,342)	(5,296)
Remeasurement adjustment			(336)
Total net benefit cost	4,971	5,431	10,611
Special termination benefits excluded from net periodic cost	100	0	2,800
NPC [Member]
Average percentage of net periodic costs capitalized [Abstract]
Average percentage of net periodic costs capitalized (in hundredths)	36.90%	37.00%	39.40%
NPC [Member] | Pension Benefits [Member]
Net periodic benefit cost [Abstract]
Service cost	9,781	9,567	9,572
Interest cost	19,521	20,092	21,079
Expected return on plan assets	24,677	21,447	17,847
Amortization of:
Prior service (credit)/cost	(1,879)	(1,733)	(1,733)
Actuarial (gain)/loss	(6,758)	(7,056)	(13,192)
Remeasurement adjustment
Total net benefit cost	9,504	13,535	24,263
NPC [Member] | Other Post-Retirement Benefits [Member]
Net periodic benefit cost [Abstract]
Service cost	1,454	1,413	1,325
Interest cost	2,459	2,474	2,437
Expected return on plan assets	2,360	2,270	2,067
Amortization of:
Prior service (credit)/cost	916	946	1,104
Actuarial (gain)/loss	(1,208)	(1,199)	(1,272)
Remeasurement adjustment			(57)
Total net benefit cost	3,677	3,762	4,128
SPPC [Member]
Average percentage of net periodic costs capitalized [Abstract]
Average percentage of net periodic costs capitalized (in hundredths)	31.70%	34.20%	36.40%
Expected federal subsidy [Abstract]
2012	0
2013	0
2014	0
2015	0
2016	0
2017-2021	0
SPPC [Member] | Pension Benefits [Member]
Net periodic benefit cost [Abstract]
Service cost	7,361	8,016
Interest cost	20,050	21,557
Expected return on plan assets	22,964	21,723
Amortization of:
Prior service (credit)/cost	(1,108)
Actuarial (gain)/loss	(9,647)	(7,876)
Remeasurement adjustment
Total net benefit cost	12,986	15,622
Expected cash flows for the plans, including trust accounts [Abstract]
2012	53,237
2013	57,364
2014	57,264
2015	56,548
2016	63,314
2017-2021	302,569
SPPC [Member] | Other Post-Retirement Benefits [Member]
Net periodic benefit cost [Abstract]
Service cost	1,086	977
Interest cost	5,830	6,187
Expected return on plan assets	3,905	3,844
Amortization of:
Prior service (credit)/cost	(4,878)	(4,851)
Actuarial (gain)/loss	(3,092)	(3,109)
Remeasurement adjustment
Total net benefit cost	1,225
Expected cash flows for the plans, including trust accounts [Abstract]
2012	9,569
2013	9,736
2014	9,984
2015	10,070
2016	10,173
2017-2021	$ 50,756

XML

STOCK COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Total Stock-Based Compensation Expense

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

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

		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		-	$	0.00		-	$	0.00		-	$	-
	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	$	-

	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

Vesting Schedule for Performance Units

Performance	Shares Vested
Below 35th Percentile	0% of grant
35th Percentile	50% of grant
50th Percentile	100% of grant
75th Percentile	150% of grant

Schedule of Nonvested Performance-based Units Activity [Table Text Block]

		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		-		-		-

Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]

		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		-		-		-

Schedule of Share-based Payment Award, Employee Stock Purchase Plan, Valuation Assumptions [Table Text Block]

			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

XML

INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY (Details) (USD $)	Dec. 31, 2011		Dec. 31, 2010
Investments in subsidiaries and other property [Line Items]
Investments held in Rabbi Trust	$ 29,182,000	[1]	$ 29,348,000	[1]
Cash Value-Life Insurance	2,735,000		2,646,000
Non-utility property of NEICO	5,517,000		5,659,000
Non-utility property of SPC	0
Property not designated for Utility use	19,235,000		23,608,000
Other non-utility property	352,000		352,000
Total investments and other property	57,021,000		61,613,000
Cash surrender value of life insurance policies	13,500,000
NPC [Member]
Investments in subsidiaries and other property [Line Items]
Investments held in Rabbi Trust	23,675,000	[2]	23,810,000	[2]
Cash Value-Life Insurance	2,735,000		2,646,000
Non-utility property of NEICO	5,517,000		5,659,000
Property not designated for Utility use	18,841,000		23,190,000
Total investments and other property	50,768,000		55,305,000
SPPC [Member]
Investments in subsidiaries and other property [Line Items]
Investments held in Rabbi Trust	5,507,000	[2]	5,538,000	[2]
Property not designated for Utility use	394,000		418,000
Total investments and other property	$ 5,901,000		$ 5,956,000

[1] Amounts recognized as non-current liabilities (accrued retirement benefits) in the consolidated balance sheets as of December 31, 2011 and 2010.

[2] 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.

XML

INCOME TAXES (BENEFITS) (Details5) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Summary of unrecognized tax benefits [Abstract]
Unrecognized tax benefits	$ 34.1	$ 35.7	$ 38.2	$ 93.9
Of the total, amounts related to tax positions that, if recognized, in future years would: Increase the effective tax rate	5.6	4.8	4.5
Sierra Pacific Power Company [Member]
Summary of unrecognized tax benefits [Abstract]
Unrecognized tax benefits	9.8	10.2	10.5	40.1
Of the total, amounts related to tax positions that, if recognized, in future years would: Increase the effective tax rate	1.8	1.6	1.4
Nevada Power Company [Member]
Summary of unrecognized tax benefits [Abstract]
Unrecognized tax benefits	24.3	25.5	26.6	48.5
Of the total, amounts related to tax positions that, if recognized, in future years would: Increase the effective tax rate	$ 3.8	$ 3.2	$ 3.1

XML

DERIVATIVES AND HEDGING ACTIVITIES, Derivative Instruments and Option Premiums (Details) (USD $) In Millions, unless otherwise specified		12 Months Ended
	Dec. 31, 2011 NPC [Member]	Dec. 31, 2009 NPC [Member] Swap [Member]	Dec. 31, 2011 NVE [Member]	Dec. 31, 2011 NVE [Member] Swap [Member]	Dec. 31, 2011 SPPC [Member]
Derivative [Line Items]
Underlying risk		interest rate		interest rate
Derivative, Notional Amount		$ 350
Amount of hedged item		350
Description of hedged item		$350 million 8.25% General and Refunding Mortgage Notes, Series A, due June 1, 2011	3-year Term Loan
Fixed interest rate (in hundredths)				2.81%
Option Premiums [Abstract]
Total Liabilities	$ (1.3)		$ (1.3)		$ 0

XML

REGULATORY ACTIONS, Deferred Energy (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Nevada Deferred Energy
Cumulative Balance authorized in DEAA	$ 334,102		$ 220,064	[1]
Amortization	247,489		74,215
Deferred Energy Over Collections	173,466	[2]	184,776	[3]
Nevada Deferred Energy Balance at period end - Subtotal	(260,079)		(330,625)
Cumulative CPUC balance			(3,210)	[4]
Reinstatement of deferred energy (effective 6/07, 10 years)	117,440		132,409
Total Deferred Energy	(142,639)		(201,426)
Deferred Assets
Deferred energy	102,525		117,623
Current Liabilities
Deferred energy	(245,164)		(315,839)
Liabilities held for sale			3,210
NPC Electric [Member]
Nevada Deferred Energy
Cumulative Balance authorized in DEAA	189,032	[5]	102,398	[1],[6]
Amortization	120,340		22,441
Deferred Energy Over Collections	106,022	[2]	106,178	[3]
Nevada Deferred Energy Balance at period end - Subtotal	(174,714)		(186,135)
Reinstatement of deferred energy (effective 6/07, 10 years)	117,440		132,409
Total Deferred Energy	(57,274)		(53,726)
SPPC Electric [Member]
Nevada Deferred Energy
Cumulative Balance authorized in DEAA	115,955		100,625	[1]
Amortization	104,909		40,682
Deferred Energy Over Collections	45,291	[2]	55,615	[3]
Nevada Deferred Energy Balance at period end - Subtotal	(56,337)		(115,558)
Cumulative CPUC balance			(3,210)	[4]
Total Deferred Energy	(56,337)		(118,768)
Current Liabilities
Deferred energy	56,337		115,558
Liabilities held for sale			3,210
SPPC Gas [Member]
Nevada Deferred Energy
Cumulative Balance authorized in DEAA	29,115		17,041	[1]
Amortization	22,240		11,092
Deferred Energy Over Collections	22,153	[2]	22,983	[3]
Nevada Deferred Energy Balance at period end - Subtotal	(29,028)		(28,932)
Total Deferred Energy	(29,028)		(28,932)
Current Liabilities
Deferred energy	$ 29,028		$ 28,932

[1] These deferred costs include PUCN ordered adjustments.

[2] These deferred energy over collections will be filed in the March 2012 DEAA filings

[3] These deferred over collections were requested in March 2011 DEAA filings.

[4] Refer to Note 16, Assets Held For Sale

[5] Refer to NPC 2011 DEAA “Settled Regulatory Actions” below for separate discussion regarding rate offset of this balance.

[6] 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.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 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):

		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.

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 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 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.

XML

DERIVATIVES AND HEDGING ACTIVITIES, Fair Value of Open Derivative Positions (Details) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010
Derivative Contracts
Risk management assets - current	$ 0		$ 4,007,000
Risk management liabilities - current	3,678,000		33,229,000
Risk management liabilities - noncurrent	1,055,000		0
NPC [Member]
Derivative Contracts
Risk management assets - current	0		3,476,000
Risk management assets - noncurrent	0		0
Risk management liabilities - current	3,678,000		22,764,000
Risk management liabilities - noncurrent	0		0
SPPC [Member]
Derivative Contracts
Risk management assets - current	0		531,000
Risk management assets - noncurrent	0		0
Risk management liabilities - current	0		10,465,000
Risk management liabilities - noncurrent	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Derivative Contracts
Risk management assets - current	0		2,100,000
Risk management assets - noncurrent	0		0
Total risk management assets	0		2,100,000
Risk management liabilities - current	2,400,000		32,900,000
Risk management liabilities - noncurrent	1,100,000		0
Derivative Liabilities	3,500,000		32,900,000
Risk management regulatory assets/liabilities - net	(3,500,000)	[1]	(30,800,000)
Gains on risk management assets, deferred to risk management regulatory assets	27,300,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | NPC [Member]
Derivative Contracts
Risk management assets - current	0		2,100,000
Risk management assets - noncurrent	0		0
Total risk management assets	0		2,100,000
Risk management liabilities - current	2,400,000		22,400,000
Risk management liabilities - noncurrent	0		0
Derivative Liabilities	2,400,000		22,400,000
Risk management regulatory assets/liabilities - net	(2,400,000)	[1]	(20,300,000)
Gains on risk management assets, deferred to risk management regulatory assets	17,900,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | SPPC [Member]
Derivative Contracts
Risk management assets - current	0		0
Risk management assets - noncurrent	0		0
Total risk management assets	0		0
Risk management liabilities - current	0		10,500,000
Risk management liabilities - noncurrent	0		0
Derivative Liabilities	0		10,500,000
Risk management regulatory assets/liabilities - net	0	[1]	(10,500,000)
Gains on risk management assets, deferred to risk management regulatory assets	$ 10,500,000

[1] For the year ended December 31, 2011, NVE, NPC and SPPC would have recorded cumulative gains of $ 27.3 million, $ 17.9 million and $ 10.5 million, 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.

XML

Schedule II Consolidated Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2011

Valuation and Qualifying Accounts [Abstract]

Schedule II - Consolidated Valuation and Qualifying Accounts

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

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

XML

SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

Schedule of Segment Reporting Information

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
Total Costs			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

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		0		588,419		233,065		233,065		-
	Purchased power		648,881		0		505,239		143,642		143,642		-
	Gas purchased for resale		137,702		0				137,702				137,702
	Deferred energy		113,107		0		94,843		18,264		8,475		9,789
Total Costs			1,721,174		0		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		0		587,647		294,121		294,121		-
	Purchased power		758,736		0		627,759		130,977		130,977		-
	Gas purchased for resale		153,607		0				153,607				153,607
	Deferred energy		289,076		0		207,611		81,465		73,829		7,636
Total Costs			2,083,187		0		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.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Gross Utility Property and CWIP

		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

Average Estimated Use Life for Major Class of Utility Property, Plant, and Equipment

	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

Schedule of Change in Asset Retirement Obligation [Table Text Block]

		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

XML

LONG-TERM DEBT, Lease Commitments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Future cash payments for capital leases [Abstract]
2011	$ 9,828
2012	9,845
2013	7,435
2014	4,831
2015	4,918
Thereafter	61,112
Total Minimum Lease Payments	97,969
Less amounts representing interest	$ (46,699)

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	12 Months Ended
	Dec. 31, 2011 number	Dec. 31, 2010	Dec. 31, 2009
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
CWIP	$ 487,427,000	$ 908,579,000
Total Utility Property, Gross	12,411,144,000	11,977,097,000
Regulated and Unregulated Operating Revenue [Abstract]
Collection period for Alternative Revenues (in months)		24 months
Asset retirement obligation [Roll Forward]
ARO balance at January 1	55,202,000	55,968,000
Liabilities incurred in current period	3,281,727.45
Liabilities settled in current period	6,996,384.55	34,000
Accretion expense	3,865,564.81	3,877,000
Revision in estimated cash flows	16,390,842.9	(4,606,000)
Gain Loss On Settlement	(762,606.45)	(3,000)
ARO balance at December 31	70,982,000	55,202,000
NPC [Member]
Basis of Presentation
Percentage of subsidiary assets to consolidated assets (in hundredths)	73.00%
Number of electricity customers	840,000
Equity Carrying Charges
Accumulated equity carrying charges	12,700,000	12,000,000
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
CWIP	352,541,000	825,079,000
Total Utility Property, Gross	8,698,312,000	8,377,176,000
Public Utilities, Allowance for Funds Used During Construction, Net Increase [Abstract]
Public Utilities, Allowance for Funds Used During Construction, Rate		8.32%	8.57%
Depreciation
Composite depreciation rate for plants in service (in hundredths)	3.04%	2.99%	2.74%
Regulated and Unregulated Operating Revenue [Abstract]
Unbilled Receivables, Current	93,000,000	89,000,000
Asset retirement obligation [Roll Forward]
ARO balance at January 1	47,126,000	48,320,000
Liabilities incurred in current period	3,281,727.45
Liabilities settled in current period	6,996,384.55	34,000
Accretion expense	3,348,038.66	3,383,000
Revision in estimated cash flows	15,021,213.94	(4,540,000)
Gain Loss On Settlement	(762,606.45)	(3,000)
ARO balance at December 31	61,017,989.05	47,126,000	48,320,000
Cost of Removal
Regulatory liabilities - cost of removal	232,000,000	208,800,000
SPPC [Member]
Basis of Presentation
Percentage of subsidiary assets to consolidated assets (in hundredths)	27.00%
Number of electricity customers	323,000
Electricity service area (in square miles)	50,000
Number of natural gas customers	152,000
Equity Carrying Charges
Accumulated equity carrying charges	900,000	1,100,000
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
CWIP	134,886,000	83,500,000
Total Utility Property, Gross	3,712,832,000	3,599,921,000
Public Utilities, Allowance for Funds Used During Construction, Net Increase [Abstract]
Public Utilities, Allowance for Funds Used During Construction, Rate			7.96%
Depreciation
Composite depreciation rate for plants in service (in hundredths)	2.89%	3.02%	3.07%
Regulated and Unregulated Operating Revenue [Abstract]
Unbilled Receivables, Current	51,000,000	60,000,000
Asset retirement obligation [Roll Forward]
ARO balance at January 1	8,076,000	7,648,000
Liabilities incurred in current period
Liabilities settled in current period
Accretion expense	517,526.15	494,000
Revision in estimated cash flows	1,369,628.96	(66,000)
Gain Loss On Settlement
ARO balance at December 31	9,964,286.27	8,076,000	7,648,000
Cost of Removal
Regulatory liabilities - cost of removal	189,900,000	173,500,000
General Plant [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
General, Intangible plant	659,000,000	657,000,000
CWIP	473,000,000	906,000,000
Common Assets	197,000,000	191,000,000
General Plant [Member] | NPC [Member]
Estimated useful lives by major class [Abtract]
General Plant assets (in years)	5 to 65 years
General Plant [Member] | SPPC [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Common Assets	197,000,000	191,000,000
Estimated useful lives by major class [Abtract]
General Plant assets (in years)	5 to 65 years
Electric General Plant [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Generation assets	4,791,000,000	4,056,000,000
Electric General Plant [Member] | NPC [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Generation assets	3,724,000,000	2,991,000,000
General, Intangible plant	564,000,000	558,000,000
CWIP	353,000,000	825,000,000
Estimated useful lives by major class [Abtract]
Generation assets (in years)	25 to 125 years
Electric General Plant [Member] | SPPC [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Generation assets	1,067,000,000	1,065,000,000
General, Intangible plant	95,000,000	99,000,000
CWIP	121,000,000	81,000,000
Estimated useful lives by major class [Abtract]
Generation assets (in years)	25 to 125 years
Transmission assets (in years)	50 to 70 years
Natural Gas General Plant [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Distribution assets	312,000,000	303,000,000
General, Intangible plant	3,000,000	3,000,000
CWIP	14,000,000	2,000,000
Natural Gas General Plant [Member] | NPC [Member]
Public Utilities, Allowance for Funds Used During Construction, Net Increase [Abstract]
Public Utilities, Allowance for Funds Used During Construction, Rate	8.47%
Natural Gas General Plant [Member] | SPPC [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
General, Intangible plant	3,000,000	3,000,000
CWIP	14,000,000	2,000,000
Electric [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Transmission assets	1,853,000,000	1,840,000,000
Distribution assets	4,108,000,000	4,019,000,000
Electric [Member] | NPC [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Transmission assets	1,183,000,000	1,183,000,000
Distribution assets	2,874,000,000	2,820,000,000
Estimated useful lives by major class [Abtract]
Transmission assets (in years)	45 to 65 years
Distribution assets (in years)	20 to 65 years
Electric [Member] | SPPC [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Transmission assets	670,000,000	657,000,000
Distribution assets	1,234,000,000	1,199,000,000
Public Utilities, Allowance for Funds Used During Construction, Net Increase [Abstract]
Public Utilities, Allowance for Funds Used During Construction, Rate	7.86%
Estimated useful lives by major class [Abtract]
Distribution assets (in years)	30 to 65 years
Natural Gas [Member] | NPC [Member]
Estimated useful lives by major class [Abtract]
Distribution assets (in years)	N/A
Natural Gas [Member] | SPPC [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]
Distribution assets	$ 312,000,000	$ 303,000,000
Public Utilities, Allowance for Funds Used During Construction, Net Increase [Abstract]
Public Utilities, Allowance for Funds Used During Construction, Rate	5.15%
Estimated useful lives by major class [Abtract]
Distribution assets (in years)	40 to 70 years

XML

REGULATORY ACTIONS (Tables)

12 Months Ended

Dec. 31, 2011

REGULATORY ACTIONS [Abstract]

Summary of Deferred Energy Amounts

				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)

				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		$	0	$	0
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)

Schedule of Regulatory Assets and Liabilities [Text Block]

		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

		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		0
	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

		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

Summary of Rate Filings

			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)

				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)

				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)

XML

INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY (Tables)

12 Months Ended

Dec. 31, 2011

INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY [Abstract]

Investments in Subsidiaries and Other Property

		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

XML

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ 202	$ 217	$ 72
Market value of risk management assets and liabilities	369
NPC [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	129	205	(96)
SPPC [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (645)	$ 116	$ 48

XML

JOINTLY OWNED FACILITIES (Tables)

12 Months Ended

Dec. 31, 2011

JOINTLY OWNED FACILITIES [Abstract]

Jointly Owned Electric Utility Facilities

		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

XML

COMMITMENTS AND CONTINGENCIES, Litigation Contingencies and Other Commitments (Details) (USD $)	12 Months Ended
	Dec. 31, 2011 MW
Capital Projects [Member]
ON Line TUA [Abstract]
Capacity of interconnection (in kV)	500
Utilities' aggregate share in transmission line project (in hundredths)	25.00%
GBT-South's share in the ON Line project (in hundredths)	75.00%
Capitalized construction costs	$ 152,300,000
Total estimated construction costs	556,000,000
NPC [Member]
Royalty claim [Abstract]
Damages sought in DC Lawsuit	600,000,000
Minimum punitive damages sought in DC Lawsuit	1,000,000,000
NPC [Member] | Capital Projects [Member]
ON Line TUA [Abstract]
Capitalized construction costs	144,100,000
SPPC [Member]
Farad Dam [Abstract]
Total capacity of hydro generating units sold (in MW)	10.3
Proceeds from sale of hydro units	8,000,000
Capacity of the Farad Hydro generating unit (in MW)	2.8
Estimate to rebuild diversion dam of the Farad Hydro generating unit	20,000,000
Amount entitled to be recovered for costs incurred to date on Farad Dam	4,000,000
Duration to rebuild the Farad dam from the date of the Court's decision	three
Amount of actual cash value entitled to if Farad Dam is not rebuilt	1,300,000
SPPC [Member] | Capital Projects [Member]
ON Line TUA [Abstract]
Capitalized construction costs	$ 8,200,000

XML

EARNINGS PER SHARE (NVE) (Tables)

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

			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

XML

JOINTLY OWNED FACILITIES (Details) (Jointly Owned Electricity Generation Plant [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 MW	Dec. 31, 2010
NPC [Member]
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 689,275	$ 666,231
Accumulated Depreciation	296,446	286,567
Net Plant in Service	392,829	379,664
CWIP	8,920	21,200
NPC [Member] | Navajo Generating Station [Member]
Jointly Owned Utility Plant Interests [Line Items]
% Owned (in hundredths)	11.30%	11.30%
Plant in Service	270,448	249,646
Accumulated Depreciation	148,582	141,326
Net Plant in Service	121,866	108,320
CWIP	1,117	1
NPC [Member] | Reid Gardner Generating Station No. 4 [Member]
Jointly Owned Utility Plant Interests [Line Items]
% Owned (in hundredths)	32.20%	32.20%
Plant in Service	171,485	165,795
Accumulated Depreciation	97,042	98,047
Net Plant in Service	74,443	67,748
CWIP	7,600	21,016
Proportionate share of base load capacity (in megawatts)	25
Proportionate share of peaking capacity (in megawatts)	232
NPC [Member] | Silverhawk Generating Station [Member]
Jointly Owned Utility Plant Interests [Line Items]
% Owned (in hundredths)	75.00%	75.00%
Plant in Service	247,342	250,790
Accumulated Depreciation	50,822	47,194
Net Plant in Service	196,520	203,596
CWIP	203	183
SPPC [Member] | Valmy Generating Station [Member]
Jointly Owned Utility Plant Interests [Line Items]
% Owned (in hundredths)	50.00%	50.00%
Plant in Service	331,753	313,378
Accumulated Depreciation	215,642	210,165
Net Plant in Service	116,111	103,213
CWIP	$ 6,682	$ 5,605
CDWR [Member] | Reid Gardner Generating Station No. 4 [Member]
Jointly Owned Utility Plant Interests [Line Items]
% Owned (in hundredths)	67.80%
Idaho Power Company [Member] | Valmy Generating Station [Member]
Jointly Owned Utility Plant Interests [Line Items]
% Owned (in hundredths)	50.00%

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Allocation of Plan Assets (Details)	Dec. 31, 2011
Pension Benefits [Member] | Cash and Cash Equivalents [Member]
Allocation of Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%
Pension Benefits [Member] | U S Equity Securities [Member]
Allocation of Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	19.00%
Defined Benefit Plan Weighted Average Target Allocation Percentage Of Assets	20.00%
Pension Benefits [Member] | International Equity Securities [Member]
Allocation of Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	14.00%
Defined Benefit Plan Weighted Average Target Allocation Percentage Of Assets	15.00%
Pension Benefits [Member] | Fixed Income Funds [Member]
Allocation of Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	61.00%
Defined Benefit Plan Weighted Average Target Allocation Percentage Of Assets	65.00%
Pension Benefits [Member] | Other [Member]
Allocation of Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	1.00%
Other Post-Retirement Benefits [Member] | Cash and Cash Equivalents [Member]
Allocation of Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	3.00%
Other Post-Retirement Benefits [Member] | Equity Securities [Member]
Allocation of Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	51.00%
Defined Benefit Plan Weighted Average Target Allocation Percentage Of Assets	60.00%
Other Post-Retirement Benefits [Member] | Fixed Income Funds [Member]
Allocation of Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations	46.00%
Defined Benefit Plan Weighted Average Target Allocation Percentage Of Assets	40.00%

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
OPERATING REVENUES:
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		0		0
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)	(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 (Benefit)	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	(357)		(403)		(128)
Change in market value of risk management assets and liabilities	(686)		0		0
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	[1]	236,294,812	[1]	235,180,688	[1]
Dividends Declared Per Share of Common Stock	$ 0.49		$ 0.45		$ 0.41
NPC [Member]
OPERATING REVENUES:
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)	(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 (Benefit)	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	(241)		(380)		175
COMPREHENSIVE INCOME	132,345		185,563		134,459
SPPC [Member]
OPERATING REVENUES:
Electric	716,417		836,879		957,130
Gas	172,482		190,943		205,263
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)	(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 (Benefit)	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	1,236		(215)		(87)
COMPREHENSIVE INCOME	$ 61,122		$ 72,160		$ 72,998

[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.

XML

SEGMENT INFORMATION (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009
Segment Reporting Information [Line Items]
Operating Revenues	$ 609,597	$ 1,017,796	$ 674,931	$ 640,983	$ 655,011	$ 1,128,039	$ 782,683	$ 714,489	$ 2,943,307	$ 3,280,222		$ 3,585,798
Energy Costs:
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	0		0
Total Costs									1,399,818	1,721,174		2,083,187
Gross Margin									1,543,489	1,559,048		1,502,611
Other Cost and Expense, Operating									411,115	414,241		453,413
Utilities Operating Expense, Maintenance									103,307	104,567		102,309
Depreciation, Depletion and Amortization, Nonproduction									357,937	333,059		321,921
Taxes, Other									60,465	62,746		60,885
Operating Income	76,684	353,196	106,919	73,866	103,435	343,364	124,730	72,906	610,665	644,435		564,083
Assets	11,635,128				11,669,668				11,635,128	11,669,668
Capital expenditures									620,516	629,496		843,132
Unallocated Amount to Segment [Member]
Segment Reporting Information [Line Items]
Operating Revenues									15	23		28
Energy Costs:
Fuel for power generation									0	0		0
Purchased power									0	0		0
Gas purchased for resale									0	0		0
Deferred energy									0	0		0
Energy efficiency program costs									0
Total Costs									0	0		0
Gross Margin									15	23		28
Other Cost and Expense, Operating									4,289	3,760		2,699
Utilities Operating Expense, Maintenance									0	0		0
Depreciation, Depletion and Amortization, Nonproduction									0	0		0
Taxes, Other									290	235		197
Operating Income									(4,564)	(3,972)		(2,868)
Assets	8,523				20,822				8,523	20,822		(25,053)
Capital expenditures									0	(13,094)	[1]	0
NPC Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenues									2,054,393	2,252,377		2,423,377
Energy Costs:
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
Total Costs									996,705	1,188,501		1,423,017
Gross Margin									1,057,688	1,063,876		1,000,360
Other Cost and Expense, Operating									260,127	260,535		279,865
Utilities Operating Expense, Maintenance									64,320	71,759		71,019
Depreciation, Depletion and Amortization, Nonproduction									252,191	226,252		215,873
Taxes, Other									37,254	37,918		37,241
Operating Income									443,796	467,412		396,362
Assets	8,442,597				8,301,824				8,442,597	8,301,824		8,096,371
Capital expenditures									475,118	499,374		656,074
SPPC Total [Member]
Segment Reporting Information [Line Items]
Operating Revenues									888,899	1,027,822		1,162,393
Energy Costs:
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
Deferred energy									(67,033)	18,264		81,465
Energy efficiency program costs									6,245
Total Costs									403,113	532,673		660,170
Gross Margin									485,786	495,149		502,223
Other Cost and Expense, Operating									146,699	149,946		170,849
Utilities Operating Expense, Maintenance									38,987	32,808		31,290
Depreciation, Depletion and Amortization, Nonproduction									105,746	106,807		106,048
Taxes, Other									22,921	24,593		23,447
Operating Income									171,433	180,995		170,589
Assets	3,184,008				3,347,022				3,184,008	3,347,022		3,342,145
Capital expenditures									145,398	143,216		187,058
SPPC Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenues									716,417	836,879		957,130
Energy Costs:
Fuel for power generation									182,098	233,065		294,121
Purchased power									156,648	143,642		130,977
Deferred energy									(65,445)	8,475		73,829
Energy efficiency program costs									6,245
Total Costs									279,546	385,182		498,927
Gross Margin									436,871	451,697		458,203
Assets	2,818,927				3,022,257				2,818,927	3,022,257		2,997,116
Capital expenditures									132,083	131,579		171,036
SPPC Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues									172,482	190,943		205,263
Energy Costs:
Gas purchased for resale									125,155	137,702		153,607
Deferred energy									(1,588)	9,789		7,636
Total Costs									123,567	147,491		161,243
Gross Margin									48,915	43,452		44,020
Assets	302,062				291,122				302,062	291,122		305,434
Capital expenditures									13,315	11,637		16,022
Intersegment Elimination [Member]
Energy Costs:
Assets	$ 63,019				$ 33,643				$ 63,019	$ 33,643		$ 39,595

[1] The capital expenditures for NVE Other at December 31, 2010 includes $13.1 million proceeds from the sale of assets between SPPC and SierraPacific Communications.

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$ 163,432	$ 226,984	$ 182,936
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	357,937	333,059	321,921
Deferred Income Taxes and Tax Credits	88,445	129,231	111,219
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(10,873)	(28,112)	(24,274)
Deferred energy	(55,429)	147,497	306,406
Gain (Loss) on Sale of Investments	0	(7,575)	0
Amortization of other regulatory assets	166,095	110,654	101,641
Deferred rate increase	79,866	(8,343)	(95,890)
Other Noncash Income (Expense)	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)
Increase (Decrease) in Pension and Postretirement Obligations	(26,845)	(18,476)	(20,080)
Other current liabilities	(14,449)	2,945	(17,287)
Increase (Decrease) in Derivative 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 Other Property, Plant, and Equipment	166,603	18,225	0
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)	0	0
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
Cash paid during period for:
Interest	314,401	336,668	325,508
Income taxes	576	754	(13,186)
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	195,511	86,127	127,786
Capital Lease Obligations Incurred	0	15,336	0
Transfer of assets to accounts receivable	0	16,830	0
NPC [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	132,586	185,943	134,284
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	252,191	226,252	215,873
Deferred Income Taxes and Tax Credits	71,971	92,859	96,831
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of 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 Noncash Income (Expense)	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)
Increase (Decrease) in Pension and Postretirement Obligations	(9,725)	(17,792)	(18,721)
Other current liabilities	(7,888)	4,959	(13,544)
Increase (Decrease) in Derivative 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 Other Property, Plant, and Equipment	31,997	3,254	0
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)
Additional investment by parent company	54,000	0	0
Settlement of interest rate lock	(14,944)	0	0
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
Cash paid during period for:
Interest	218,693	226,138	217,807
Income taxes	1	2	2
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	175,661	74,557	117,226
Capital Lease Obligations Incurred	0	15,336	0
SPPC [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	59,886	72,375	73,085
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	105,746	106,807	106,048
Deferred Income Taxes and Tax Credits	31,487	39,220	32,548
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(2,575)	(2,883)	(3,249)
Deferred energy	(58,978)	31,267	89,777
Gain (Loss) on Sale of Investments	0	(7,575)	0
Amortization of other regulatory assets	81,636	35,799	39,146
Other Noncash Income (Expense)	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)
Increase (Decrease) in Pension and Postretirement Obligations	(18,401)	(2,523)	(2,227)
Other current liabilities	(2,131)	721	(3,038)
Increase (Decrease) in Derivative 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 Other Property, Plant, and Equipment	134,606	14,971	0
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 FROM 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)
Additional investment by parent company	0	0	90,300
Dividends paid	(114,000)	(54,000)	(128,800)
Net Cash from/(used by) Financing Activities	(130,977)	(164,981)	(147,110)
Net Increase 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
Cash paid during period for:
Interest	59,605	67,351	69,966
Income taxes	575	752	12
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	19,850	11,570	10,560
Transfer of assets to accounts receivable	0	16,830	0
Dividends	$ 0	$ 54,000	$ 0

XML

DEBT COVENANT AND OTHER RESTRICTIONS, Dividends (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended						3 Months Ended								12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 NPC [Member]	Dec. 31, 2011 SPPC [Member]	Dec. 31, 2011 NVE [Member]	Sep. 30, 2011 NVE [Member]	Jun. 30, 2011 NVE [Member]	Mar. 31, 2011 NVE [Member]	Dec. 31, 2010 NVE [Member]	Sep. 30, 2010 NVE [Member]	Jun. 30, 2010 NVE [Member]	Mar. 31, 2010 NVE [Member]	Dec. 31, 2011 NVE [Member]
Dividends [Abstract]
Dividend declaration date					Feb. 10, 2012	Feb. 10, 2012									Feb. 10, 2012
Dividend declared to parent company						$ 20									$ 39
Common Stock, Dividends, Per Share, Declared	$ 0.49	$ (115,587,000.00)	$ 0.45	$ 0.41			$ 0.13	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.11	$ 0.11	$ 0.11
Dividends Payable, Date of Record, Day, Month and Year															Mar. 06, 2012

XML

INCOME TAXES (BENEFITS) (Tables)

12 Months Ended

Dec. 31, 2011

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

		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		-		-		0.0
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

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	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			196.0			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			0.0			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	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

			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		428.7		198.0		179.3
Valuation allowance			(1.2)		(1.2)		0.0		(1.5)		(1.5)		0.0
Total deferred tax assets after valuation allowance		$	682.6	$	460.5	$	154.8	$	427.2	$	196.5	$	179.3

			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

Net Operating Loss and Tax Credit Carryovers

	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

	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

Summary of Unrecognized Tax Benefits

		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

	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

XML

INCOME TAXES (BENEFITS) (Details3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Components of Deferred Tax Assets [Abstract]
Net operating loss and credit carryovers	$ 470.8	$ 173.8
Employee benefit plans	58.4	66.3
Customer advances	17.6	25.2
Gross-ups received on CIAC & customer advances	20.3	26.2
Deferred revenues	18.5	8.0
Deferred energy	49.9	70.5
Reserves	13.4	11.3
Other	17.5	27.9
Total deferred tax assets - Non-Regulatory	666.4	409.2
Regulatory deferred tax assets
Excess deferred income taxes	8.7	9.2
Unamortized investment tax credit	8.7	10.3
Deferred Tax Assets, Regulatory Assets and Liabilities	17.4	19.5
Total deferred tax assets before valuation allowance	683.8	428.7
Valuation allowance	1.2	1.5
Total deferred tax assets after valuation allowance	682.6	427.2
Deferred tax liabilities [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,380.7	1,004.2
Deferred Conservation Programs	83.2	78.8
Regulatory assets	137.1	166.1
Other	32.0	36.6
Total deferred tax liabilities - Non-Regulatory	1,633.0	1,285.7
Regulatory deferred tax liabilities
Tax benefits flowed through to customers - property	115.2	116.9
Tax benefits flowed through to customers - goodwill	136.0	140.2
Deferred Tax Liabilities, Regulatory Assets and Liabilities	251.2	257.1
Total deferred tax liabilities, including regulatory deferred tax liabilities	1,884.2	1,542.8
Deferred tax assets and liabilities net non regulatory	967.8	878.0
Deferred tax assets liabilities net regulatory	233.8	237.6
Deferred Tax Assets (Liabilities), Net	1,201.6	1,115.6
Nevada Power Company [Member]
Components of Deferred Tax Assets [Abstract]
Net operating loss and credit carryovers	353.7	82.5
Employee benefit plans	21.2	25.7
Customer advances	10.5	12.3
Gross-ups received on CIAC & customer advances	15.3	19.4
Deferred revenues	15.1	3.5
Deferred energy	20.0	18.8
Reserves	9.6	9.9
Other	10.5	19.3
Total deferred tax assets - Non-Regulatory	455.9	191.4
Regulatory deferred tax assets
Excess deferred income taxes	2.5	2.7
Unamortized investment tax credit	3.3	3.9
Deferred Tax Assets, Regulatory Assets and Liabilities	5.8	6.6
Total deferred tax assets before valuation allowance	461.7	198.0
Valuation allowance	1.2	1.5
Total deferred tax assets after valuation allowance	460.5	196.5
Deferred tax liabilities [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	1,015.1	661.7
Deferred Conservation Programs	63.0	58.6
Regulatory assets	94.1	112.9
Other	19.4	21.1
Total deferred tax liabilities - Non-Regulatory	1,191.6	854.3
Regulatory deferred tax liabilities
Tax benefits flowed through to customers - property	93.0	86.3
Tax benefits flowed through to customers - goodwill	85.0	87.7
Deferred Tax Liabilities, Regulatory Assets and Liabilities	178.0	174.0
Total deferred tax liabilities, including regulatory deferred tax liabilities	1,369.6	1,028.3
Deferred tax assets and liabilities net non regulatory	736.9	664.3
Deferred tax assets liabilities net regulatory	172.2	167.5
Deferred Tax Assets (Liabilities), Net	909.1	831.8
Sierra Pacific Power Company [Member]
Components of Deferred Tax Assets [Abstract]
Net operating loss and credit carryovers	62.5	46.3
Employee benefit plans	26.5	34.8
Customer advances	7.1	12.9
Gross-ups received on CIAC & customer advances	5.0	6.8
Deferred revenues	3.4	4.5
Deferred energy	29.9	51.7
Reserves	2.5	1.4
Other	6.3	7.9
Total deferred tax assets - Non-Regulatory	143.2	166.3
Regulatory deferred tax assets
Excess deferred income taxes	6.2	6.5
Unamortized investment tax credit	5.4	6.5
Deferred Tax Assets, Regulatory Assets and Liabilities	11.6	13.0
Total deferred tax assets before valuation allowance	154.8	179.3
Valuation allowance	0	0
Total deferred tax assets after valuation allowance	154.8	179.3
Deferred tax liabilities [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	371.6	348.9
Deferred Conservation Programs	20.2	20.1
Regulatory assets	44.2	54.3
Other	12.1	15.1
Total deferred tax liabilities - Non-Regulatory	448.1	438.4
Regulatory deferred tax liabilities
Tax benefits flowed through to customers - property	22.3	30.6
Tax benefits flowed through to customers - goodwill	50.9	52.5
Deferred Tax Liabilities, Regulatory Assets and Liabilities	73.2	83.1
Total deferred tax liabilities, including regulatory deferred tax liabilities	521.3	521.5
Deferred tax assets and liabilities net non regulatory	304.9	272.1
Deferred tax assets liabilities net regulatory	61.6	70.1
Deferred Tax Assets (Liabilities), Net	$ 366.5	$ 342.2

XML

COMMON STOCK AND OTHER PAID-IN CAPITAL

12 Months Ended

Dec. 31, 2011

Equity [Abstract]

COMMON STOCK AND OTHER PAID-IN CAPITAL

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. 

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.

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2011

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Funded Status [Table Text Block]

						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)

Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets

						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	$	-	$	-

Amortization of Regulatory Assets for Pension Plans and Accumulated Other Comprehensive Income Into Net Periodic Cost

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)

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]

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

Schedule of Allocation of Plan Assets [Table Text Block]

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

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

Schedule of Assumptions Used [Table Text Block]

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

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

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)

Schedule of Net Benefit Costs [Table Text Block]

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

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

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

Schedule of Expected Benefit Payments [Table Text Block]

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		-

XML

ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2011

ASSETS HELD FOR SALE [Abstract]

ASSETS HELD FOR SALE

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.

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.

XML

INCOME TAXES (BENEFITS) (Details6) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Unrecognized tax benefits [Roll Forward]
Begining Balance		$ 35.7	$ 38.2	$ 93.9
Increase in current period tax positions		0.5	0.3	3.3
Increase in prior period tax positions		0.2	0.1	11.8
Decrease in prior period tax positions	(64.4)	2.3	2.9	70.8
Ending Balance		34.1	35.7	38.2
Sierra Pacific Power Company [Member]
Unrecognized tax benefits [Roll Forward]
Begining Balance		10.2	10.5	40.1
Increase in current period tax positions		0.1	0.2	0.5
Increase in prior period tax positions		0.1	0.1	2.5
Decrease in prior period tax positions	(32.2)	0.6	0.6	32.6
Ending Balance		9.8	10.2	10.5
Nevada Power Company [Member]
Unrecognized tax benefits [Roll Forward]
Begining Balance		25.5	26.6	48.5
Increase in current period tax positions		0.4	0.1	2.8
Increase in prior period tax positions		0.1	0.1	9.2
Decrease in prior period tax positions	(32.0)	1.7	1.3	33.9
Ending Balance		$ 24.3	$ 25.5	$ 26.6

XML

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $) In Thousands, except Share data	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	NPC [Member]	NPC [Member] Common Stock [Member]	NPC [Member] Additional Paid-in Capital [Member]	NPC [Member] Retained Earnings [Member]	NPC [Member] Accumulated Other Comprehensive Income (Loss) [Member]	SPPC [Member]	SPPC [Member] Common Stock [Member]	SPPC [Member] Additional Paid-in Capital [Member]	SPPC [Member] Retained Earnings [Member]	SPPC [Member] Accumulated Other Comprehensive Income (Loss) [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2008	$ 3,131,185	$ 234,317	$ 2,694,792	$ 208,436	$ (6,360)	$ 2,627,573	$ 1	$ 2,254,182	$ 377,061	$ (3,671)	$ 877,960	$ 4	$ 1,020,960	$ (140,686)	$ (2,318)
Balance (in shares) at Dec. 31, 2008		234,316,829					1,000					1,000
Net Income	182,936			182,936		134,284			134,284		73,085			73,085
Dividend Reinvestment and Employee Benefits	6,047	517	5,530
Dividend Reinvestment and Employee Benefits (in shares)		517,340
Tax benefit from stock options exercised	7		7			7		7
Capital contribution from parent											90,300		90,300
Change in market value of risk management assets and liabilities	0
Change in compensation retirement benefits liability and amortization	(128)				(128)	175				175	(87)				(87)
Dividends Declared	(96,125)			(96,125)		(112,000)			(112,000)		(32,000)			(32,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2009	3,223,922	234,834	2,700,329	295,247	(6,488)	2,650,039	1	2,254,189	399,345	(3,496)	1,009,258	4	1,111,260	(99,601)	(2,405)
Balance (in shares) at Dec. 31, 2009		234,834,169					1,000					1,000
Net Income	(1,721)					(12,326)					17,120
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Mar. 31, 2010
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2009	3,223,922	234,834	2,700,329	295,247	(6,488)	2,650,039	1		399,345	(3,496)	1,009,258	4	1,111,260	(99,601)	(2,405)
Balance (in shares) at Dec. 31, 2009		234,834,169					1,000					1,000
Net Income	226,984			226,984		185,943			185,943		72,375			72,375
Dividend Reinvestment and Employee Benefits	6,109	489	5,620
Dividend Reinvestment and Employee Benefits (in shares)		488,384
Tax benefit from stock options exercised	32		32								2		2
Change in market value of risk management assets and liabilities	0
Change in compensation retirement benefits liability and amortization	(403)				(403)	(380)				(380)	(215)				(215)
Common stock issuance costs	(27)		(27)
Dividends Declared	(105,799)			(105,799)		(74,000)			(74,000)		(108,000)			(108,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2010	3,350,818	235,323	2,705,954	416,432	(6,891)	2,761,632	1		511,288	(3,876)	973,420	4	1,111,262	(135,226)	(2,620)
Balance (in shares) at Dec. 31, 2010	235,322,553	235,322,553				1,000	1,000				1,000	1,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2010
Net Income	14,213					9,557					19,478
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2010	3,350,818					2,761,632	1				973,420	4
Balance (in shares) at Dec. 31, 2010	235,322,553					1,000	1,000				1,000	1,000
Net Income	2,330					(9,020)					16,576
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Mar. 31, 2011
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2010	3,350,818	235,323	2,705,954	416,432	(6,891)	2,761,632	1	2,254,219	511,288	(3,876)	973,420	4		(135,226)	(2,620)
Balance (in shares) at Dec. 31, 2010	235,322,553	235,322,553				1,000	1,000				1,000	1,000
Net Income	163,432			163,432		132,586			132,586		59,886			59,886
Dividend Reinvestment and Employee Benefits	8,459	677	7,782
Dividend Reinvestment and Employee Benefits (in shares)		677,197
Tax benefit from stock options exercised						30		30
Capital contribution from parent						54,000		54,000
Change in market value of risk management assets and liabilities	(686)				(686)
Change in compensation retirement benefits liability and amortization	(357)				(357)	(241)				(241)	1,236				1,236
Dividends Declared				(115,587)		(99,000)			(99,000)		(60,000)			(60,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2011	3,406,079	236,000	2,713,736	464,277	(7,934)	2,848,977	1	2,308,219	544,874	(4,117)	974,542	4	1,111,262	(135,340)	(1,384)
Balance (in shares) at Dec. 31, 2011	235,999,750	235,999,750				1,000	1,000				1,000	1,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2011
Net Income	(25,248)					(29,065)					14,462
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2011	$ 3,406,079					$ 2,848,977	$ 1				$ 974,542	$ 4	$ 1,111,262
Balance (in shares) at Dec. 31, 2011	235,999,750					1,000	1,000				1,000	1,000

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
OTHER INCOME (EXPENSE):
AFUDC-debt	$ (8,718)	$ (23,355)	$ (20,229)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	202	217	72
Market value of risk management assets and liabilities	369
NPC [Member]
OTHER INCOME (EXPENSE):
AFUDC-debt	(6,770)	(21,443)	(17,184)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	129	205	(96)
SPPC [Member]
OTHER INCOME (EXPENSE):
AFUDC-debt	(1,948)	(1,912)	(3,044)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (645)	$ 116	$ 48

XML

DERIVATIVES AND HEDGING ACTIVITIES

12 Months Ended

Dec. 31, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES AND HEDGING ACTIVITIES

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 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):

	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	$	0.0
Risk management assets - noncurrent		-		-		-		-		-		0.0
Total risk management assets		-		-		-		2.1		2.1		0.0
Risk management liabilities- current		2.4		2.4		-		32.9		22.4		10.5
Risk management liabilities- noncurrent		1.1		-		-		-		-		0.0
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)

• 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.

XML

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011
Entity Information [Line Items]
Entity Registrant Name	NV Energy, Inc.
Entity Central Index Key	0000741508
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float	$ 3,622,247,595
Entity Common Stock, Shares Outstanding	235,999,750
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011
NPC [Member]
Entity Information [Line Items]
Entity Registrant Name	Nevada Power Company
Entity Central Index Key	0000071180
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,000
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011
SPPC [Member]
Entity Information [Line Items]
Entity Registrant Name	Sierra Pacific Power Company
Entity Central Index Key	0000090144
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,000
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011

XML

INCOME TAXES (BENEFITS)

12 Months Ended

Dec. 31, 2011

Income Tax Disclosure [Abstract]

INCOME TAXES (BENEFITS)

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		-		-		0.0
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

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			196.0			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			0.0			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		428.7		198.0		179.3
Valuation allowance			(1.2)		(1.2)		0.0		(1.5)		(1.5)		0.0
Total deferred tax assets after valuation allowance		$	682.6	$	460.5	$	154.8	$	427.2	$	196.5	$	179.3

			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

	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 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.

XML

STOCK COMPENSATION PLANS (Purcahse rights assumption) (Details) (Employee Stock Purchase Plan [Member])	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Employee Stock Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average Dividend Yield (in hundredths)	3.42%	2.79%	3.90%
Average Expected Volatility (in hundredths)	13.99%	20.02%	28.89%
Average Risk-Free Rate of Return (in hundredths)	0.11%	0.22%	0.22%
Weighted-Average Fair Value	2.82	2.55	2.54

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 145,944	$ 86,189
Accounts receivable less allowance for uncollectible accounts	355,091	354,010
Materials, supplies and fuel, at average cost	129,663	114,520
Risk management assets (Note 9)	0	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
Public Utilities, Property, Plant and Equipment, Net [Abstract]
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
Public Utilities, Property, Plant and Equipment, Net	9,227,073	8,929,659
Investments and other property, net (Note 4)	57,021	61,613
Other Assets, Noncurrent [Abstract]
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 Assets, Noncurrent	74,206	166,882
Total Deferred Charges and Other Assets	1,578,514	1,791,136
Assets Held-for-sale, Long Lived	0	155,322
Assets	11,635,128	11,669,668
Current Liabilities:
Current maturities of long-term debt (Note 6)	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	0	0
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	0
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)	0	30,706
Shareholders' Equity
Common stock	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)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,406,079	3,350,818
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	11,635,128	11,669,668
NPC [Member]
Current Assets:
Cash and cash equivalents	65,887	60,077
Accounts receivable less allowance for uncollectible accounts	233,096	224,704
Materials, supplies and fuel, at average cost	72,529	66,459
Risk management assets (Note 9)	0	3,476
Intercompany income taxes receivable	0	0
Deferred income taxes (Note 10)	88,782	76,282
Other current assets	28,943	29,680
Total Current Assets	489,237	460,678
Public Utilities, Property, Plant and Equipment, Net [Abstract]
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
Public Utilities, Property, Plant and Equipment, Net	6,791,695	6,548,810
Investments and other property, net (Note 4)	50,768	55,305
Other Assets, Noncurrent [Abstract]
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
Risk management assets (Note 9)	0	0
Other Assets, Noncurrent	46,855	114,016
Total Deferred Charges and Other Assets	1,110,897	1,237,031
Assets	8,442,597	8,301,824
Current Liabilities:
Current maturities of long-term debt (Note 6)	139,985	355,929
Accounts Payable	182,183	232,279
Accounts Payable, Related Parties, Current	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
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
Risk management liabilities (Note 9)	0	0
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
Shareholders' Equity
Common stock	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)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	2,848,977	2,761,632
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	8,442,597	8,301,824
SPPC [Member]
Current Assets:
Cash and cash equivalents	55,195	9,552
Accounts receivable less allowance for uncollectible accounts	121,863	129,306
Materials, supplies and fuel, at average cost	57,134	48,061
Risk management assets (Note 9)	0	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
Public Utilities, Property, Plant and Equipment, Net [Abstract]
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
Public Utilities, Property, Plant and Equipment, Net	2,435,378	2,380,849
Investments and other property, net (Note 4)	5,901	5,956
Other Assets, Noncurrent [Abstract]
Regulatory assets (Note 3)	333,138	365,177
Regulatory asset for pension plans (Note 3)	104,159	131,734
Risk management assets (Note 9)	0	0
Other Assets, Noncurrent	21,074	45,268
Total Deferred Charges and Other Assets	458,371	542,179
Assets Held-for-sale, Long Lived	0	155,322
Assets	3,184,008	3,347,022
Current Liabilities:
Current maturities of long-term debt (Note 6)	0	0
Accounts Payable	99,897	90,206
Accounts Payable, Related Parties, Current	27,788	10,812
Accrued expenses	32,840	33,788
Dividends Payable	0	54,000
Risk management liabilities (Note 9)	0	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
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
Risk management liabilities (Note 9)	0	0
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)	0	30,706
Shareholders' Equity
Common stock	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)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	974,542	973,420
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 3,184,008	$ 3,347,022

XML

INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY

12 Months Ended

Dec. 31, 2011

INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY [Abstract]

Investments and Other Noncurrent Assets [Text Block]

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.

XML

REGULATORY ACTIONS

12 Months Ended

Dec. 31, 2011

REGULATORY ACTIONS [Abstract]

REGULATORY ACTIONS

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 SignificantAccounting 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		$	0	$	0
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)

(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

		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		0
	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

		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.

       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 another 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.

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;
• 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.

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.

       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 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.

XML

EARNINGS PER SHARE (NVE)

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

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.

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2011

Compensation and Retirement Disclosure [Abstract]

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

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.

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	$	-	$	-

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 post-retirement 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 postretirement benefits assets at December 31, 2011 and 2010, 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):

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

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.

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.

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 plansponsor's assets.

XML

COMMON STOCK AND OTHER PAID-IN CAPITAL (Details) (USD $)	12 Months Ended				3 Months Ended								12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 NVE [Member]	Sep. 30, 2011 NVE [Member]	Jun. 30, 2011 NVE [Member]	Mar. 31, 2011 NVE [Member]	Dec. 31, 2010 NVE [Member]	Sep. 30, 2010 NVE [Member]	Jun. 30, 2010 NVE [Member]	Mar. 31, 2010 NVE [Member]	Dec. 31, 2011 NVE [Member]	Dec. 31, 2011 NPC [Member]	Dec. 31, 2011 SPPC [Member]	Dec. 31, 2011 Non Employee Director Stock Plan [Member]	Dec. 31, 2010 Non Employee Director Stock Plan [Member]	Dec. 31, 2009 Non Employee Director Stock Plan [Member]	Dec. 31, 2011 Common Stock Investment Plan [Member]	Dec. 31, 2011 Employee Stock Purchase Plan [Member]
Warrants and Rights Note Disclosure [Abstract]
Period from adoption that rights plan shall expire, if plan is adopted without prior shareholder approval (in years)	one year	one year
Stock Ownership Plans [Abstract]
Shares of common stock reserved for issuance under the Stock Plans (in shares)	13,350,162	13,350,162
Maximum employee percentage deduction for ESPP purchases (in hundredths)																				15.00%
Share-based Compensation Arrangement by Share-based Payment Award, Discount from Market Price, Offering Date																				85.00%
Non-Employee Director Stock [Abstract]
Annual retainer for non-employee directors		$ 135,000
Minimum amount of retainer to be paid in stock		75,000
Granted shares to non-employee directors (in shares)																49,002	65,933	93,729
Share based compensation granted to non-employee directors																745,879	829,077	968,229
Common Stock Investment Plan [Abstract]
Minimum initial purchase for new investors																			250
Minimum purchase amount for existing shareholders																			50
Dividend reinvestment increments (in hundredths)																			10.00%
Dividends Payable [Line Items]
Dividends Declared Per Share of Common Stock	$ 0.49	$ (115,587,000)	$ 0.45	$ 0.41	$ 0.13	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.11	$ 0.11	$ 0.11
Dividends [Abstract]
Declaration date													Feb. 10, 2012	Feb. 10, 2012	Feb. 10, 2012
Dividends Payable, Date to be Paid, Day, Month and Year													Mar. 21, 2012
Dividends Payable, Date of Record, Day, Month and Year													Mar. 06, 2012
Dividend declared to parent company													$ 39,000,000		$ 20,000,000

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2011

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

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.

XML

DEBT COVENANT AND OTHER RESTRICTIONS, Ability to Issue Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2011
Ability to issue debt [Abstract]
Covenant terms	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 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
Maximum additional indebtedness the entity is allowed to incur under covenant	$ 2,800,000,000
NPC [Member] | Financing Authority from PUCN [Member]
Ability to issue debt [Abstract]
Maximum additional indebtedness the entity is allowed to incur under covenant	725,000,000
Maximum amount of refinancing of long-term debt securities	322,500,000
NPC [Member] | Financing Authority from PUCN [Member] | Revolving Credit Facility [Member]
Ability to issue debt [Abstract]
Maximum amount of credit facility the entity has authority to maintain	1,300,000,000
NPC [Member] | Financial Covenants Within Financing Agreements [Member] | Revolving Credit Facility [Member]
Ability to issue debt [Abstract]
Covenant terms	ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1
Maximum additional indebtedness the entity is allowed to incur under covenant	2,600,000,000
Maximum amount of credit facility the entity has authority to maintain	600,000,000
NPC [Member] | Indenture [Member] | General and Refunding Mortgage Securities [Member]
Ability to issue debt [Abstract]
Maximum additional indebtedness the entity is allowed to incur under covenant	1,400,000,000
Amount of secured debt outstanding	4,100,000,000
Percent of net utility property additions on which capacity to issue additional debt is based (in hundredths)	70.00%
SPPC [Member] | Financing Authority from PUCN [Member]
Ability to issue debt [Abstract]
Maximum additional indebtedness the entity is allowed to incur under covenant	350,000,000
Maximum amount of refinancing of long-term debt securities	348,000,000
SPPC [Member] | Financing Authority from PUCN [Member] | Revolving Credit Facility [Member]
Ability to issue debt [Abstract]
Maximum amount of credit facility the entity has authority to maintain	600,000,000
SPPC [Member] | Financial Covenants Within Financing Agreements [Member] | Revolving Credit Facility [Member]
Ability to issue debt [Abstract]
Covenant terms	ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1
Maximum additional indebtedness the entity is allowed to incur under covenant	879,000,000
Maximum amount of credit facility the entity has authority to maintain	250,000,000
SPPC [Member] | Indenture [Member] | General and Refunding Mortgage Securities [Member]
Ability to issue debt [Abstract]
Maximum additional indebtedness the entity is allowed to incur under covenant	760,300,000
Amount of secured debt outstanding	$ 1,500,000,000
Percent of net utility property additions on which capacity to issue additional debt is based (in hundredths)	70.00%

XML

JOINTLY OWNED FACILITIES

12 Months Ended

Dec. 31, 2011

JOINTLY OWNED FACILITIES [Abstract]

JOINTLY OWNED FACILITIES

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.

XML

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Long-term Debt [Text Block]

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	$	0	$	0	$	0	$	0	$	350,000	$	0	$	350,000	$	0
		6.50% NPC Series I due 2012		130,000		0		130,000		0		130,000		0		130,000		0
		5.875% NPC Series L due 2015		250,000		0		250,000		0		250,000		0		250,000		0
		5.95% NPC Series M due 2016		210,000		0		210,000		0		210,000		0		210,000		0
		6.65% NPC Series N due 2036		370,000		0		370,000		0		370,000		0		370,000		0
		6.50% NPC Series O due 2018		325,000		0		325,000		0		325,000		0		325,000		0
		6.75% NPC Series R due 2037		350,000		0		350,000		0		350,000		0		350,000		0
		6.50% NPC Series S due 2018		500,000		0		500,000		0		500,000		0		500,000		0
		7.375% NPC Series U due 2014		125,000		0		125,000		0		125,000		0		125,000		0
		7.125% NPC Series V due 2019		500,000		0		500,000		0		500,000		0		500,000		0
		5.375% NPC Series X due 2040		250,000		0		250,000		0		250,000		0		250,000		0
		5.45% NPC Series Y due 2041		250,000		0		250,000		0		0		0		0		0
		6.00% SPPC Series M due 2016		450,000		0		0		450,000		450,000		0		0		450,000
		6.75% SPPC Series P due 2037		251,742		0		0		251,742		251,742		0		0		251,742
		5.45% SPPC Series Q due 2013		250,000		0		0		250,000		250,000		0		0		250,000
	Variable Rate Debt (Secured by
		General and Refunding Mortgage
		Securities)
		NPC IDRB Series 2000A due 2020		98,100		0		98,100		0		98,100		0		98,100		0
		NPC PCRB Series 2006 due 2036		37,700		0		37,700		0		37,700		0		37,700		0
		NPC PCRB Series 2006A due 2032		37,975		0		37,975		0		37,975		0		37,975		0
		SPPC PCRB Series 2006A due 2031		58,200		0		0		58,200		58,200		0		0		58,200
		SPPC PCRB Series 2006B due 2036		75,000		0		0		75,000		75,000		0		0		75,000
		SPPC PCRB Series 2006C due 2036		81,475		0		0		81,475		81,475		0		0		81,475
		Revolving Credit Facilities		0		0		0		0		15,000		0		0		15,000
Senior Notes
		6.75% NVE Senior Notes due 2017		0		0		0		0		191,500		191,500		0		0
		6.25% NVE Senior Notes due 2020		315,000		315,000		0		0		315,000		315,000		0		0
		2.81% NVE Term Loan due 2014		195,000		195,000		0		0		0		0		0		0
Obligations under capital leases				51,270		0		51,270		0		55,735		0		55,735		0
Unamortized bond premium
and discount, net				(12,546)		0		(25,455)		12,909		2,611		1		(11,748)		14,358
Current maturities				(139,985)		0		(139,985)		0		(355,929)		0		(355,929)		0
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

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 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 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.

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.

XML

DEBT COVENANT AND OTHER RESTRICTIONS

12 Months Ended

Dec. 31, 2011

DEBT COVENANT AND OTHER RESTRICTIONS [Abstract]

DEBT COVENANT AND OTHER RESTRICTIONS

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.

 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 $725million 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, 2011financial 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

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, 2011financial 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.

XML

INCOME TAXES (BENEFITS) (Details2) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income tax reconciliation [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (25,248,000)	$ 173,462,000	$ 12,888,000	$ 2,330,000	$ 14,213,000	$ 177,546,000	$ 36,946,000	$ (1,721,000)	$ 163,432,000	$ 226,984,000	$ 182,936,000
Income Tax Expense (Benefit)									86,915,000	113,764,000	75,451,000
Income Before Income Tax Expense									250,347,000	340,748,000	258,387,000
Statutory tax rate (in hundredths)									35.00%	35.00%	35.00%
Federal income tax expense									87,600,000	119,300,000	90,400,000
Depreciation									3,100,000	4,100,000	(2,100,000)
AFUDC - equity									3,800,000	9,800,000	8,500,000
Investment tax credit amortization									3,100,000	3,300,000	3,300,000
Regulatory asset for goodwill									2,700,000	2,700,000	2,700,000
Research and development credit									200,000	1,000,000	1,100,000
Income Tax Reconciliation, Other Reconciling Items									600,000	1,800,000	(2,500,000)
Effective tax rate (in hundredths)									34.70%	33.40%	29.20%
Nevada Power Company [Member]
Income tax reconciliation [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(29,065,000)	154,608,000	16,063,000	(9,020,000)	9,557,000	158,928,000	29,784,000	(12,326,000)	132,586,000	185,943,000	134,284,000
Income Tax Expense (Benefit)									70,737,000	91,757,000	61,652,000
Income Before Income Tax Expense									203,323,000	277,700,000	195,936,000
Statutory tax rate (in hundredths)									35.00%	35.00%	35.00%
Federal income tax expense									71,200,000	97,200,000	68,600,000
Depreciation									2,000,000	1,800,000	1,700,000
AFUDC - equity									2,900,000	8,800,000	7,400,000
Investment tax credit amortization									1,200,000	1,400,000	1,300,000
Regulatory asset for goodwill									1,700,000	1,700,000	1,700,000
Research and development credit									100,000	800,000	1,000,000
Income Tax Reconciliation, Other Reconciling Items									0	2,100,000	(600,000)
Effective tax rate (in hundredths)									34.80%	33.10%	31.50%
Sierra Pacific Power Company [Member]
Income tax reconciliation [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	14,462,000	25,336,000	3,512,000	16,576,000	19,478,000	24,462,000	11,315,000	17,120,000	59,886,000	72,375,000	73,085,000
Income Tax Expense (Benefit)									31,197,000	40,404,000	31,225,000
Income Before Income Tax Expense									91,083,000	112,779,000	104,310,000
Statutory tax rate (in hundredths)									35.00%	35.00%	35.00%
Federal income tax expense									31,900,000	39,500,000	36,500,000
Depreciation									1,100,000	2,300,000	(3,800,000)
AFUDC - equity									900,000	1,000,000	1,100,000
Investment tax credit amortization									1,900,000	1,900,000	2,100,000
Regulatory asset for goodwill									1,000,000	1,000,000	1,000,000
Research and development credit									100,000	200,000	200,000
Income Tax Reconciliation, Other Reconciling Items									$ 100,000	$ 700,000	$ 900,000
Effective tax rate (in hundredths)									34.20%	35.80%	29.90%

XML

EARNINGS PER SHARE (NVE) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Numerator
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (25,248)	$ 173,462	$ 12,888	$ 2,330	$ 14,213	$ 177,546	$ 36,946	$ (1,721)	$ 163,432		$ 226,984		$ 182,936
Denominator
Weighted Average Shares of Common Stock Outstanding - basic									235,847,596		235,048,347		234,542,292
Per Share Amounts
Net income per share - basic	$ (0.11)	$ 0.74	$ 0.05	$ 0.01	$ 0.06	$ 0.76	$ 0.16	$ (0.01)	$ 0.69		$ 0.97		$ 0.78
Numerator
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (25,248)	$ 173,462	$ 12,888	$ 2,330	$ 14,213	$ 177,546	$ 36,946	$ (1,721)	$ 163,432		$ 226,984		$ 182,936
Denominator
Weighted Average Number of Shares Outstanding, Basic									235,847,596		235,048,347		234,542,292
Stock options (in shares)									36,189		34,590		27,596
Non-Employee Director stock plan (in shares)									143,791		141,577		100,244
Employee stock purchase plan (in shares)									4,111		5,909		7,331
Restricted Shares (in shares)									395,813		78,920		12,389
Performance Shares (in shares)									1,339,571		985,469		490,836
Weighted Average Number of Shares Outstanding, Diluted									237,767,071	[1]	236,294,812	[1]	235,180,688	[1]
Per Share Amounts
Net income per share - diluted	$ (0.11)	$ 0.73	$ 0.05	$ 0.01	$ 0.06	$ 0.75	$ 0.16	$ (0.01)	$ 0.69		$ 0.96		$ 0.78
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									557,793		701,658		679,272

[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.

XML

INCOME TAXES (BENEFITS) (Details4) (USD $) In Millions, unless otherwise specified							12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 Sierra Pacific Power Company [Member]	Dec. 31, 2010 Sierra Pacific Power Company [Member]	Dec. 31, 2011 Nevada Power Company [Member]	Dec. 31, 2010 Nevada Power Company [Member]	Dec. 31, 2011 Research [Member]	Dec. 31, 2011 Research [Member] Sierra Pacific Power Company [Member]	Dec. 31, 2011 Research [Member] Nevada Power Company [Member]	Dec. 31, 2011 General Business [Member]	Dec. 31, 2011 General Business [Member] Nevada Power Company [Member]	Dec. 31, 2011 Internal Revenue Service (IRS) [Member]	Dec. 31, 2011 Internal Revenue Service (IRS) [Member] Sierra Pacific Power Company [Member]	Dec. 31, 2011 Internal Revenue Service (IRS) [Member] Nevada Power Company [Member]
Operating loss and Tax Credit carryfowards [Line Items]
Deferred tax asset, Net operating loss carryforward												$ 456.5	$ 58.1	$ 343.7
Deferred tax asset, Tax credit carryforward							12.6	4.4	8.3	1.7	1.7
Deferred tax asset, Total net operating loss and tax credits	470.8	173.8	62.5	46.3	353.7	82.5
Valuation allowance, Net operating loss carryforward												0	0	0
Valuation allowance, Tax credit carryforward							0	0	0	1.2	1.2
Valuation allowance, Total net operating loss and tax credits	1.2		0		1.2
Net deferred tax asset, Net operating loss carryforward												456.5	58.1	343.7
Net deferred tax asset, Tax credit carryforward							12.6	4.4	8.3	0.5	0.5
Net deferred tax asset, Total net operating loss and tax credits	469.6		62.5		352.5
Expiration period, Net operating loss carryforward												2024-2031	2024-2031	2024-2031
Expiration period, Tax credit carryforward							2024-2031	2024-2031	2024-2031	2012-2016	2012-2016
Gross NOL carryover												$ 1,300.0	$ 166.0	$ 982.0

XML

INCOME TAXES (BENEFITS) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Current and other [Abstract]
Federal	$ (1.3)	$ (15.4)	$ (34.1)
State	0.1	1.0	0
Total current and other	(1.2)	(14.4)	(34.1)
Deferred [Abstract]
Federal	91.7	132.7	114.1
State	(0.1)	(0.1)	0.5
Total deferred	91.6	132.6	114.6
Amortization of excess deferred taxes	0.4	1.1	1.7
Investment tax credits	3.1	3.3	3.3
Summary of unrecognized tax benefits [Abstract]
Unrecognized tax benefits	34.1	35.7	38.2	93.9
Of the total, amounts related to tax positions that, if recognized, in future years would: Increase the effective tax rate	5.6	4.8	4.5
SPPC [Member]
Current and other [Abstract]
Federal	(0.1)	1.1	(0.5)
State	0.1	0.9	0
Total current and other	0	2.0	(0.5)
Deferred [Abstract]
Federal	33.2	42.0	34.3
State	0.2	(0.9)	0.3
Total deferred	33.4	41.1	34.6
Amortization of excess deferred taxes	0.3	0.8	0.8
Investment tax credits	1.9	1.9	2.1
Summary of unrecognized tax benefits [Abstract]
Unrecognized tax benefits	9.8	10.2	10.5	40.1
Of the total, amounts related to tax positions that, if recognized, in future years would: Increase the effective tax rate	1.8	1.6	1.4
NPC [Member]
Current and other [Abstract]
Federal	(1.1)	(0.9)	(34.3)
State	0	0
Total current and other	(1.1)	(0.9)	(34.3)
Deferred [Abstract]
Federal	73.4	93.6	97.9
State	(0.3)	0.7	0.3
Total deferred	73.1	94.3	98.2
Amortization of excess deferred taxes	0.1	0.2	0.9
Investment tax credits	1.2	1.4	1.3
Summary of unrecognized tax benefits [Abstract]
Unrecognized tax benefits	24.3	25.5	26.6	48.5
Of the total, amounts related to tax positions that, if recognized, in future years would: Increase the effective tax rate	$ 3.8	$ 3.2	$ 3.1

XML

DERIVATIVES AND HEDGING ACTIVITIES (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value, Measurement Inputs, Disclosure [Table Text Block]

	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	$	0.0
Risk management assets - noncurrent		-		-		-		-		-		0.0
Total risk management assets		-		-		-		2.1		2.1		0.0
Risk management liabilities- current		2.4		2.4		-		32.9		22.4		10.5
Risk management liabilities- noncurrent		1.1		-		-		-		-		0.0
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)

XML

REGULATORY ACTIONS, FERC Matters (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
NPC [Member]
FERC Matters [Abstract]
Receivable from CAISO and CALPX	$ 19
SPPC [Member]
FERC Matters [Abstract]
Receivable from CAISO and CALPX	1
Additional liability recorded related to receivable	$ 3

XML

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

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

		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.

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 requested.

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 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 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.

XML

QUARTERLY FINANCIAL DATA (UNAUDITED)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data [Abstract]

Quarterly Financial Information [Text Block]

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

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

XML

REGULATORY ACTIONS, Summary of Regulatory Actions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			12 Months Ended			12 Months Ended										12 Months Ended		12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011 NPC [Member]	Dec. 31, 2010 NPC [Member]	Dec. 31, 2011 NPC [Member] DEAA [Member]	Dec. 31, 2010 NPC [Member] DEAA [Member]	Dec. 31, 2009 NPC [Member] DEAA [Member]	Dec. 31, 2011 NPC [Member] REPR [Member]	Dec. 31, 2011 NPC [Member] TRED [Member]	Dec. 31, 2011 NPC [Member] EEPR Base [Member]	Dec. 31, 2011 NPC [Member] EEPR Amortization [Member]	Dec. 31, 2011 NPC [Member] EEIR Base [Member]	Dec. 31, 2011 NPC [Member] EEIR Amortization [Member]		Dec. 31, 2011 NPC [Member] GRC [Member]	Dec. 31, 2010 NPC [Member] GRC [Member]	Dec. 31, 2008 NPC [Member] GRC [Member]	Dec. 31, 2011 SPPC [Member]	Dec. 31, 2009 SPPC [Member] DEAA [Member]	Dec. 31, 2011 SPPC [Member] SPPC Gas [Member] DEAA [Member]	Dec. 31, 2010 SPPC [Member] SPPC Gas [Member] DEAA [Member]	Dec. 31, 2009 SPPC [Member] SPPC Gas [Member] DEAA [Member]	Dec. 31, 2011 SPPC [Member] SPPC Gas [Member] STPR [Member]	Dec. 31, 2010 SPPC [Member] SPPC Gas [Member] GRC [Member]	Dec. 31, 2011 SPPC [Member] SPPC Electric [Member]	Dec. 31, 2011 SPPC [Member] SPPC Electric [Member] DEAA [Member]	Dec. 31, 2010 SPPC [Member] SPPC Electric [Member] DEAA [Member]	Dec. 31, 2009 SPPC [Member] SPPC Electric [Member] DEAA [Member]	Dec. 31, 2011 SPPC [Member] SPPC Electric [Member] REPR [Member]	Dec. 31, 2011 SPPC [Member] SPPC Electric [Member] TRED [Member]	Dec. 31, 2011 SPPC [Member] SPPC Electric [Member] EEPR Base [Member]	Dec. 31, 2011 SPPC [Member] SPPC Electric [Member] EEPR Amortization [Member]	Dec. 31, 2011 SPPC [Member] SPPC Electric [Member] EEIR Base [Member]	Dec. 31, 2011 SPPC [Member] SPPC Electric [Member] EEIR Amortization [Member]	Dec. 31, 2010 SPPC [Member] SPPC Electric [Member] GRC [Member]	Dec. 31, 2008 SPPC [Member] SPPC California [Member] GRC [Member]
Ely Energy Center [Abstract]
Spending amount approved by Public Utility Commission of Nevada on Ely Energy Center	$ 130
Amount spent on Ely Energy Center and recorded as other deferred asset	58.0
Farming Asset Reclassification		23.1
Development And Farming Asset Reclassification																	11.6
EEC Development Costs		23.2
Energy Efficiency Implementation Rate [Abstract]
Approximate revenues filed for estimated reduced kWh sales from energy efficiency program		35.1															7.6
Increases to EEIR base rates authorized		14.5															2.6
Pre-tax adjustment to earnings for revenue previously recorded		4.5															4.1
Revenues recognized for EEIR		15.5															2.5
Energy Efficiency Program Rate [Abstract]
Frequency of rate filings for energy efficiency program costs (in years)	3 years
Approximate costs filed for implementing energy efficiency programs		71.0															12.1
Increases to Energy Efficiency Program base rates authorized		58.4															9.7
EEPR revenues recorded		37.3															6.2
GRC Filings [Abstract]
Requested Increase In General Rates														249.9		305.7							4.3												8.9
Requested return on equity (in hundredths)		11.25%														11.00%							10.75%											10.75%	11.40%
Requested rate of return (in hundredths)		8.64%														8.88%							5.48%											8.14%	8.81%
Recovery, excluding AFUDC, for the expansion at the Harry Allen Generating Station		635.9
Increase in General Rates														158.6		222.7							2.7											13.1	5.5
Percentage Overall Increase In General Rates														8.30%		9.80%							1.93%											1.90%	8.00%
Approved ROE		10.00%														10.50%							10.00%											10.10%	10.70%
Allowed ROR		8.09%														8.53%							5.15%											7.86%
Dsm Costs		17.7
Mohave Closure Costs		12.7
EWAM Postponement Amount		46.9
Net Rate Case Adjustments														15.9
Revenue Requirement Subject To Change:
Anticipated Effective Date				Oct. 2011			Oct. 2011	Oct. 2011	Oct. 2011	Oct. 2011	Oct. 2011	Oct. 2011							Oct. 2011			Oct. 2011			Oct. 2011			Oct. 2011	Oct. 2011	Oct. 2011	Oct. 2011	Oct. 2011	Oct. 2011
Requested and Amended Revenue Requirement	(28.8)	(60.6)		(188.9)			8.6	18.1	58.4	21.3	17.1	4.8	[1]						(29.1)			0.3		(50.9)	(115.9)			38.0	9.1	9.7	4.6	3.1	0.5
Present Revenue Requirement	(16.7)	18.0		(101.0)			29.8	16.3	58.4		14.5								(16.7)					(42.7)	(99.5)			36.6	7.9	9.7		2.6
$ Change in Revenue Requirement	(12.1)	(78.6)		(87.9)			(21.2)	1.8		21.3	2.6	4.8							(12.4)			0.3		(8.2)	(16.4)			1.4	1.2		4.6	0.5	0.5
DEAA Filings [Abstract]
Requested rate increase (decrease)						72.1															8.7						25.9
Requested rate increase (decrease) percentage (in hundredths)						3.18%												2.69%			4.71%
Deferred costs refund requested			102.0			77.5														17.0	8.7					101.0	19.8
Amount Of Over Collection Against Deferred Btgr Debit Balance					102
Deferred Base Tariff General Rate balance															$ 95.8

[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

XML

ASSETS HELD FOR SALE (Tables)

12 Months Ended

Dec. 31, 2011

ASSETS HELD FOR SALE [Abstract]

Disclosure of Long Lived Assets Held-for-sale [Table Text Block]

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

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	$ 8,150	$ 28,684
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common Stock, Par or Stated Value Per Share	$ 1.00	$ 1.00
Common stock, shares authorized (in shares)	350,000,000	350,000,000
Common stock, shares issued (in shares)	235,999,750	235,322,553
Common stock, shares outstanding (in shares)	235,999,750	235,322,553
NPC [Member]
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	6,751	26,428
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common Stock, Par or Stated Value Per Share	$ 1.00	$ 1.00
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares issued (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	1,000	1,000
SPPC [Member]
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	$ 1,399	$ 2,256
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Common Stock, Par or Stated Value Per Share	$ 3.75	$ 3.75
Common stock, shares authorized (in shares)	20,000,000	20,000,000
Common stock, shares issued (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	1,000	1,000

XML

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Quarterly Financial Data [Line Items]
Operating Revenues	$ 609,597	$ 1,017,796	$ 674,931	$ 640,983	$ 655,011	$ 1,128,039	$ 782,683	$ 714,489	$ 2,943,307	$ 3,280,222	$ 3,585,798
Operating Income	76,684	353,196	106,919	73,866	103,435	343,364	124,730	72,906	610,665	644,435	564,083
Net Income (Loss)	(25,248)	173,462	12,888	2,330	14,213	177,546	36,946	(1,721)	163,432	226,984	182,936
Earnings Per Share, Basic and Diluted [Abstract]
Net income per share - basic	$ (0.11)	$ 0.74	$ 0.05	$ 0.01	$ 0.06	$ 0.76	$ 0.16	$ (0.01)	$ 0.69	$ 0.97	$ 0.78
Net income per share - diluted	$ (0.11)	$ 0.73	$ 0.05	$ 0.01	$ 0.06	$ 0.75	$ 0.16	$ (0.01)	$ 0.69	$ 0.96	$ 0.78
Income Tax Expense (Benefit)									86,915	113,764	75,451
NPC [Member]
Quarterly Financial Data [Line Items]
Operating Revenues	391,513	798,914	473,898	390,068	416,233	870,950	539,395	425,799	2,054,393	2,252,377	2,423,377
Operating Income	33,759	296,327	82,177	31,533	55,450	288,163	93,670	30,129	443,796	467,412	396,362
Net Income (Loss)	(29,065)	154,608	16,063	(9,020)	9,557	158,928	29,784	(12,326)	132,586	185,943	134,284
Earnings Per Share, Basic and Diluted [Abstract]
Income Tax Expense (Benefit)									70,737	91,757	61,652
SPPC [Member]
Quarterly Financial Data [Line Items]
Operating Revenues	218,080	218,878	201,030	250,911	238,774	257,084	243,282	288,682	888,899	1,027,822	1,162,393
Operating Income	45,007	57,574	25,703	43,149	49,184	56,223	32,184	43,404	171,433	180,995	170,589
Net Income (Loss)	14,462	25,336	3,512	16,576	19,478	24,462	11,315	17,120	59,886	72,375	73,085
Earnings Per Share, Basic and Diluted [Abstract]
Income Tax Expense (Benefit)									$ 31,197	$ 40,404	$ 31,225

XML

SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

SEGMENT INFORMATION

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 ClarkCounty 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 Consolidated 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
Total Costs			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

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		0		588,419		233,065		233,065		-
	Purchased power		648,881		0		505,239		143,642		143,642		-
	Gas purchased for resale		137,702		0				137,702				137,702
	Deferred energy		113,107		0		94,843		18,264		8,475		9,789
Total Costs			1,721,174		0		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		0		587,647		294,121		294,121		-
	Purchased power		758,736		0		627,759		130,977		130,977		-
	Gas purchased for resale		153,607		0				153,607				153,607
	Deferred energy		289,076		0		207,611		81,465		73,829		7,636
Total Costs			2,083,187		0		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.

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $) In Billions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 6.0	$ 5.7
NPC [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	4.1	3.9
SPPC [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 1.3	$ 1.3

XML

COMMITMENTS AND CONTINGENCIES, Environmental (Details) (NPC [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011
NPC [Member]
Environmental [Abstract]
Reclamation estimate of coal washing and load-out facility site	$ 5

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Plan Changes (Details) (USD $) In Thousands, unless otherwise specified						12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2011 Supplemental Executive Retirement and Restoration Plans [Member]	Dec. 31, 2011 Contract with IBEW No. 1245 Amendment [Member] Pension Benefits [Member]	Dec. 31, 2011 MPAT Amendment [Member] Other Post-Retirement Benefits [Member]	Dec. 31, 2011 Amendment to Cap Company Contributions [Member] Other Post-Retirement Benefits [Member]	Dec. 31, 2011 Amendment to Cap Company Contributions [Member] Supplemental Executive Retirement and Restoration Plans [Member]
Defined Benefit Plan Amendments [Line Items]
Plan changes, description						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.
Trust assets	$ 29,182	[1]	$ 29,348	[1]	$ 29,200

[1] Amounts recognized as non-current liabilities (accrued retirement benefits) in the consolidated balance sheets as of December 31, 2011 and 2010.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Basis of Presentation

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

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 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.

Utility Plant

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):

		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

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

AFUDC

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.

Impairment of Long-Lived Assets

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 and Cash Equivalents

Cash is comprised of cash on hand and working funds.  Cash equivalents consist of high quality investments in money market funds and do not have any withdrawal restrictions.

Federal Income Taxes

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.

Utility, Revenue and Expense Recognition, Policy [Policy Text Block]

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.

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.

Alternative Revenues

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.

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

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 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

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.

Fair Value Measurements and Disclosures

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 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.

Comprehensive Income Policy [Policy Text Block]

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.

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Assumptions (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Actuarial assumptions used to determine benefit obligations [Abstract]
Discount rate (in hundredths)	4.91%	5.09%
Rate of compensation increase (in hundredths)	4.00%	4.00%
Initial health care cost trend rate (in hundredths)	8.00%	8.00%
Ultimate health care cost trend rate (in hundredths)	4.75%	4.75%
Number of years to ultimate trend rate (in years)	7	8
Actuarial assumptions used to determine net periodic benefit costs [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.09%	5.79%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.00%	4.50%
Initial health care cost trend rate (in hundredths)	8.00%	8.00%
Ultimate health care cost trend rate (in hundredths)	4.75%	5.00%
Number of years to ultimate trend rate (in years)	8	7
Effect of one-percentage-point change in assumed health care cost trend rates [Abstract]
Effect of one percentage point increase on the postretirement benefit obligation	$ 6,446
Effect of one percentage point increase on total of service and interest cost components	696
Effect of one percentage point decrease on the postretirement benefit obligation	(5,251)
Effect of one percentage point decrease on total of service and interest cost components	$ (542)
Maximum [Member]
Actuarial assumptions used to determine net periodic benefit costs [Abstract]
Percentile yields on portfolio of high quality AA bonds (in hundredths)	90.00%
Minimum [Member]
Actuarial assumptions used to determine net periodic benefit costs [Abstract]
Portfolio high quality Aa bonds matched to, minimum (number of bonds)	300
Percentile yields on portfolio of high quality AA bonds (in hundredths)	10.00%
Pension Benefits [Member]
Actuarial assumptions used to determine net periodic benefit costs [Abstract]
Expected long-term rate of return on plan assets, range minimum (in hundredths)	6.75%	6.75%
Other Post-Retirement Benefits [Member]
Actuarial assumptions used to determine benefit obligations [Abstract]
Discount rate (in hundredths)	5.09%	5.20%
Actuarial assumptions used to determine net periodic benefit costs [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.20%	5.75%
Other Post-Retirement Benefits [Member] | Maximum [Member]
Actuarial assumptions used to determine net periodic benefit costs [Abstract]
Expected long-term rate of return on plan assets, range minimum (in hundredths)	7.10%	7.10%
Other Post-Retirement Benefits [Member] | Minimum [Member]
Actuarial assumptions used to determine net periodic benefit costs [Abstract]
Expected long-term rate of return on plan assets, range minimum (in hundredths)	6.75%	6.75%

XML

COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Contractual Obligations

		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

		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

XML

STOCK COMPENSATION PLANS

12 Months Ended

Dec. 31, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

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.

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		-	$	0.00		-	$	0.00		-	$	-
	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.

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.

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.

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