10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED   September 30, 2013

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM      TO  

	Registrant, Address of	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	Number	Incorporation
001-08788	NV ENERGY, INC.	88-0198358	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada  89146
	(702) 402-5000
000-52378	NEVADA POWER COMPANY d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000
000-00508	SIERRA PACIFIC POWER COMPANY d/b/a	88-0044418	Nevada
	NV ENERGY
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

Indicate by check mark whether registrant (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    (Response applicable to all registrants)

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 whether any registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer", "accelerated filer", "non-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 Exchange Act).    Yes  o  No  þ  (Response applicable to all registrants)

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

Class	Outstanding at November 1, 2013
Common Stock, $1.00 par value of NV Energy, Inc.	235,581,074 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 stated value, of Sierra Pacific Power Company.

This combined Quarterly Report on Form 10-Q 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

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2013

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
Acronyms & Terms				3
ITEM 1.	Financial Statements
	NV Energy, Inc.
			Consolidated Statements of Comprehensive Income  – Three and Nine Months Ended September 30, 2013 and 2012	5
			Consolidated Balance Sheets – September 30, 2013 and December 31, 2012	6
			Consolidated Statements of Cash Flows -  Nine Months Ended September 30, 2013 and 2012	8
			Consolidated Statements of Shareholders’ Equity -  Nine Months Ended September 30, 2013 and 2012	9
	Nevada Power Company
			Consolidated Statements of Comprehensive Income   –  Three and Nine Months Ended September 30, 2013 and 2012	10
			Consolidated Balance Sheets – September 30, 2013 and December 31, 2012	11
			Consolidated Statements of Cash Flows -  Nine Months Ended September 30, 2013  and 2012	13
			Consolidated Statements of Shareholder’s Equity - Nine  Months Ended September 30, 2013 and 2012	14
	Sierra Pacific Power Company
			Consolidated Statements of Comprehensive Income   –  Three and Nine Months Ended September 30, 2013 and 2012	15
			Consolidated Balance Sheets – September 30, 2013 and December 31, 2012	16
			Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2013 and 2012	18
			Consolidated Statements of Shareholder’s Equity -  Nine Months Ended September 30, 2013 and 2012	19
	Condensed Notes to Financial Statements
			Note 1.     Summary of Significant Accounting Policies	20
			Note 2.     Merger-Related Activities	21
			Note 3.     Segment Information	22
			Note 4.     Regulatory Actions	25
			Note 5.     Long-Term Debt	29
			Note 6.     Fair Value of Financial Instruments	30
			Note 7.     Retirement Plan and Post-Retirement Benefits	30
			Note 8.     Commitments and Contingencies	32
			Note 9.     Earnings per Share (NVE)	38
			Note 10.   Common Stock and Other Paid-In Capital	38
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			40
	NV Energy, Inc.			46
	Nevada Power Company			51
	Sierra Pacific Power Company			61
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk			73
ITEM 4.	Controls and Procedures			73
PART II – OTHER INFORMATION
ITEM 1.		Legal Proceedings		74
ITEM 1A.		Risk Factors		74
ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds		74
ITEM 3.		Defaults Upon Senior Securities		74
ITEM 4.		Mine Safety Disclosures		74
ITEM 5.		Other Information		74
ITEM 6.		Exhibits		75
Signature Page and Certifications				77

2

ACRONYMS AND TERMS

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

Acronym/Term	Meaning
2012 Form 10-K	NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2012
AFUDC-debt	Allowance for Borrowed Funds Used During Construction
AFUDC-equity	Allowance for Equity Funds Used During Construction
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
BOD	Board of Directors
BTER	Base Tariff Energy Rate
BTGR	Base Tariff General Rate
CA ISO	California Independent System Operator Corporation
California Assets	SPPC's California electric distribution and generation assets
CalPeco	California Pacific Electric Company
CDD	Cooling degree days
CDWR	California Department of Water Resources
CIAC	Contributions in Aid of Construction
CWIP	Construction Work-in-Progress
dba	Doing business as
DEAA	Deferred Energy Accounting Adjustment
Dth	Decatherm
EEIR	Energy Efficiency Implementation Rate
EEPR	Energy Efficiency Program Rate
EPA	Environmental Protection Agency
EPS	Earnings per Share
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	Generally Accepted Accounting Principles in the United States
GBT	Great Basin Transmission, LLC, a wholly owned subsidiary of Texas Nevada Transmission, LLC
GBT-South	Great Basin Transmission South, LLC, a wholly owned subsidiary of GBT
GRC	General Rate Case
Harry Allen Generating Station	642 megawatt nominally rated Harry Allen Generating Station
HDD	Heating degree days
Higgins Generating Station	598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP	Integrated resource plan
kV	Kilovolt
Lenzie Generating Station	1,102 megawatt nominally rated Chuck Lenzie Generating Station
MEHC	MidAmerican Energy Holdings Company, an Iowa corporation, and subsidiary of Berkshire Hathaway, Inc.
MidAmerican Merger	The merger contemplated by the MidAmerican Merger Agreement of Silver Merger Sub, Inc., a Nevada corporation
	and wholly-owned subsidiary of MEHC, with and into NVE, with NVE continuing as the surviving corporation.
MidAmerican Merger	The agreement and plan of merger dated as of May 29, 2013, among NVE, MEHC and Silver Merger Sub, Inc.,
Agreement	a Nevada corporation and wholly-owned subsidiary of MEHC
Mohave Generating Station	1,580 megawatt nominally rated Mohave Generating Station
Moody’s	Moody’s Investors Services, Inc.
MW	Megawatt
MWh	Megawatt hour
Navajo Generating Station	255 megawatt nominally rated Navajo Generating Station
NEICO	Nevada Electric Investment Company
NERC	North American Electric Reliability Corporation
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	$500 million Revolving Credit Facility entered into in March 2012 between NPC and Wells Fargo Bank,
	N.A., as administrative agent for the lenders a party thereto

3

NPC 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	A smart grid infrastructure that is expected to enable the widespread use of Smart Meters that will provide
	customers the ability to more directly manage their energy usage
NVEOC	NV Energy Operating Company
NVision	A comprehensive plan of NVE for the reduction of emissions from coal-fired generation plants through the
	accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with
	increased capacity from renewable energy facilities and other electric generating plants
ON Line	250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
One Company Merger	The merger between NPC and SPPC, whereby SPPC will be merged into NPC and the surviving entity will be called NVEOC
Portfolio Standard	Nevada Renewable Energy Portfolio Standard
PUCN	Public Utilities Commission of Nevada
Reid Gardner Generating Station	325 megawatt nominally rated Reid Gardner Generating Station
REPR	Renewable Energy Program Rate
ROR	Rate of return
SB 123	Senate Bill 123 passed into law by the Nevada State Legislature in June 2013, requiring certain electric utilities in
	Nevada to file with the PUCN an emissions reduction and capacity replacement plan; and prescribing the minimum
	requirements of such a plan
S&P	Standard & Poor's
Salt River	Salt River Project
SEC	United States Securities and Exchange Commission
Silverhawk Generating Station	395 megawatt nominally rated Silverhawk Generating Station
SPPC	Sierra Pacific Power Company d/b/a NV Energy
SPPC Credit Agreement	$250 million Revolving Credit Facility entered into in March 2012 between SPPC and Wells Fargo
	Bank, N.A., as administrative agent for the lenders a party thereto
SPPC 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
Term Loan	$195 million loan agreement entered into on October 7, 2011 between NVE and JPMorgan Chase Bank,
	N.A., as administrative agent for the lenders a party thereto
TMWA	Truckee Meadows Water Authority
Tracy Generating Station	541 megawatt nominally rated Frank A. Tracy Generating Station
TRED	Temporary Renewable Energy Development
TUA	Transmission Use and Capacity Exchange Agreement with GBT-South
U.S.	United States of America
Utilities	Nevada Power Company and Sierra Pacific Power Company
Valmy Generating Station	261 megawatt nominally rated Valmy Generating Station
VIE	Variable Interest Entity
WSPP	Western Systems Power Pool

4

ITEM 1.                              FINANCIAL STATEMENTS

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
OPERATING REVENUES	$	1,013,151		$	1,026,488		$	2,329,011		$	2,378,606
OPERATING EXPENSES:
Fuel for power generation	217,954			171,316			554,181			400,936
Purchased power	205,970			205,686			498,141			486,894
Gas purchased for resale	7,383			5,382			62,277			46,491
Deferred energy	(55,270		)	(29,036		)	(221,022		)	(30,285		)
Energy efficiency program costs	16,042			32,584			38,486			76,609
Regulatory disallowance	17,335			—			17,335			—
Merger-related costs (Note 2)	7,857			—			21,409			—
Other operating expenses	106,068			100,108			317,538			307,080
Maintenance	17,176			19,014			66,128			76,190
Depreciation and amortization	96,801			94,512			291,687			281,690
Taxes other than income	14,214			15,682			46,536			44,457
Total Operating Expenses	651,530			615,248			1,692,696			1,690,062
OPERATING INCOME	361,621			411,240			636,315			688,544
OTHER INCOME (EXPENSE):
Interest expense
(net of AFUDC-debt: $1,957 , $1,976 , $5,770 and $5,479)	(74,438		)	(73,667		)	(221,305		)	(226,162		)
Interest expense on regulatory items	(281		)	(2,024		)	(1,124		)	(6,203		)
AFUDC-equity	2,591			2,415			7,730			6,666
Other income	3,239			8,827			10,872			19,312
Other expense	(3,829		)	(4,209		)	(12,116		)	(11,909		)
Total Other Income (Expense)	(72,718		)	(68,658		)	(215,943		)	(218,296		)
Income Before Income Tax Expense	288,903			342,582			420,372			470,248
Income tax expense	101,669			119,412			148,430			165,466
NET INCOME	187,234			223,170			271,942			304,782
Other comprehensive income (loss)
Change in compensation retirement benefits liability and amortization
(Net of taxes $(133), $(74), $(398) and $(246))	246			155			738			464
Change in market value of risk management assets and liabilities
(Net of taxes $(154), $91, $(261) and $355)	(11		)	(193		)	485			(668		)
Unrealized net gain/(loss) on investment
(Net of taxes $(49), $0, $(18) and $0)	98			—			33			—
OTHER COMPREHENSIVE INCOME(LOSS)	333			(38		)	1,256			(204		)
COMPREHENSIVE INCOME	$	187,567		$	223,132		$	273,198		$	304,578
Amount per share basic and diluted (Note 9)
Net income per share - basic	$	0.79		$	0.95		$	1.16		$	1.29
Net income per share - diluted	$	0.79		$	0.94		$	1.15		$	1.28
Weighted Average Shares of Common Stock Outstanding - basic	235,578,310			235,961,402			235,421,933			235,986,874
Weighted Average Shares of Common Stock Outstanding - diluted	237,605,514			238,121,732			237,339,039			237,850,530
Dividends Declared Per Share of Common Stock	$	0.19		$	0.17		$	0.57		$	0.47
The accompanying notes are an integral part of the financial statements.

5

NV ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			September 30,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	373,026	$	298,271
	Accounts receivable less allowance for uncollectible accounts:
		2013 - $9,643; 2012 - $8,748	483,178		373,099
	Materials, supplies and fuel, at average cost		121,699		138,337
	Deferred energy costs (Note 4)		82,235		—
	Deferred income taxes		120,186		60,592
	Other current assets		49,041		40,750
Total Current Assets			1,229,365		911,049
Utility Property:
	Plant in service		12,195,312		12,031,053
	Construction work-in-progress		821,430		708,109
		Total	13,016,742		12,739,162
	Less accumulated provision for depreciation		3,526,824		3,313,188
		Total Utility Property, Net	9,489,918		9,425,974
Investments and other property, net			65,354		56,660
Deferred Charges and Other Assets:
	Deferred energy (Note 4)		85,055		87,072
	Regulatory assets		1,048,204		1,132,768
	Regulatory asset for pension plans		270,565		281,195
	Other deferred charges and assets		76,705		89,418
Total Deferred Charges and Other Assets			1,480,529		1,590,453
TOTAL ASSETS			$	12,265,166	$	11,984,136
		(Continued)

6

NV ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

		September 30,			December 31,
		2013			2012
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 5)	$	129,457		$	356,283
	Accounts payable	316,681			332,245
	Accrued expenses	104,781			127,693
	Deferred energy (Note 4)	—			136,865
	Other current liabilities	88,299			66,221
Total Current Liabilities		639,218			1,019,307
Long-term debt (Note 5)		4,791,809			4,669,798
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
	Deferred income taxes	1,680,896			1,470,973
	Deferred investment tax credit	11,623			13,538
	Accrued retirement benefits	144,696			162,260
	Regulatory liabilities	631,368			550,687
	Other deferred credits and liabilities	656,963			540,202
Total Deferred Credits and Other Liabilities		3,125,546			2,737,660
Shareholders' Equity:
	Common stock, $1.00 par value; 350 million shares authorized; 235,999,750 issued
	for 2013 and 2012; 235,581,074 and 235,079,156 outstanding for 2013 and 2012, respectively	236,000			236,000
	Treasury stock at cost, 418,675 shares and 920,594 shares for 2013 and 2012, respectively	(7,898		)	(16,804		)
	Other paid-in capital	2,716,311			2,712,943
	Retained earnings	772,995			635,303
	Accumulated other comprehensive loss	(8,815		)	(10,071		)
Total Shareholders' Equity		3,708,593			3,557,371
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	12,265,166		$	11,984,136
	The accompanying notes are an integral part of the financial statements.
	(Concluded)

7

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Nine Months Ended
			September 30,
			2013			2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	271,942		$	304,782
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization	291,687			281,690
		Deferred taxes and deferred investment tax credit	152,280			187,229
		AFUDC-equity	(7,730		)	(6,666		)
		Deferred energy	(218,156		)	(18,702		)
		Regulatory disallowance	17,335			—
		Amortization of other regulatory assets	134,846			114,626
		Deferred rate increase	9,241			2,252
		Other, net	3,649			(50,012		)
	Changes in certain assets and liabilities:
		Accounts receivable	(101,079		)	(151,420		)
		Materials, supplies and fuel	16,909			(18,034		)
		Other current assets	(8,292		)	(10,390		)
		Accounts payable	7,042			22,646
		Accrued retirement benefits	(17,563		)	(12,946		)
		Other current liabilities	(594		)	(23,643		)
		Other deferred assets	(3,634		)	(3,572		)
		Other regulatory assets	(3,276		)	34,420
		Other deferred liabilities	9,099			(8,066		)
Net Cash from Operating Activities			553,706			644,194
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)	(267,798		)	(387,790		)
		Customer advances for construction	921			(1,508		)
		Contributions in aid of construction	38,714			63,864
		Investments and other property - net	(5,144		)	217
Net Cash used by Investing Activities			(233,307		)	(325,217		)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs	247,245			130,764
		Retirement of long-term debt	(354,443		)	(272,353		)
		Sale of common stock	2,133			—
		Common stock repurchased	(6,329		)	(4,509		)
		Dividends paid	(134,250		)	(110,920		)
Net Cash used by Financing Activities			(245,644		)	(257,018		)
Net Increase in Cash and Cash Equivalents			74,755			61,959
Beginning Balance in Cash and Cash Equivalents			298,271			145,944
Ending Balance in Cash and Cash Equivalents			$	373,026		$	207,903
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	233,502		$	237,262
		Income taxes	$	2		$	151
	Significant non-cash transactions:
		Accrued construction expenses as of September 30,	$	141,214		$	132,112
		Issuance of treasury stock	$	13,102		$	—
		The accompanying notes are an integral part of the financial statements.

8

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

	Common Stock Shares	Common Stock Amount		Treasury Stock Shares		Treasury Stock Amount			Other Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders' Equity
December 31, 2011	235,999,750	$	236,000	—		$	—		$	2,713,736	$	464,277		$	(7,934	)	$	3,406,079
Net Income											304,782						304,782
Change in compensation retirement benefits liability and amortization (net of taxes $(246))														464			464
Change in market value of risk management assets and liabilities (net of taxes $355)														(668		)	(668		)
Common stock repurchased				(252,000	)	(4,509		)									(4,509		)
Dividends Declared											(110,920		)				(110,920		)
September 30, 2012	235,999,750	$	236,000	(252,000	)	$	(4,509	)	$	2,713,736	$	658,139		$	(8,138	)	$	3,595,228
December 31, 2012	235,999,750	$	236,000	(920,594	)	$	(16,804	)	$	2,712,943	$	635,303		$	(10,071	)	$	3,557,371
Net Income											271,942						271,942
Employee Benefits				827,097		15,235			3,368								18,603
Change in compensation retirement benefits liability and amortization (net of taxes $(398))														738			738
Change in market value of risk management assets and liabilities (net of taxes $(261))														485			485
Unrealized net gain/(loss) on investment (net of taxes $(18))														33			33
Common stock repurchased				(325,178	)	(6,329		)									(6,329		)
Dividends Declared											(134,250		)				(134,250		)
September 30, 2013	235,999,750	$	236,000	(418,675	)	$	(7,898	)	$	2,716,311	$	772,995		$	(8,815	)	$	3,708,593
The accompanying notes are an integral part of the financial statements.

9

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
OPERATING REVENUES		$	786,142		$	802,334		$	1,695,129		$	1,751,165
OPERATING EXPENSES:
	Fuel for power generation	163,127			123,992			412,904			285,799
	Purchased power	172,582			171,687			383,386			388,494
	Deferred energy	(45,381		)	(22,685		)	(154,484		)	(15,461		)
	Energy efficiency program costs	13,998			28,492			32,807			65,466
	Regulatory disallowance	11,866			—			11,866			—
	Merger-related costs (Note 2)	5,620			—			14,487			—
	Other operating expenses	70,844			65,372			208,336			200,484
	Maintenance	11,208			12,533			45,172			52,594
	Depreciation and amortization	68,849			66,975			207,915			201,096
	Taxes other than income	8,213			9,743			27,804			26,793
Total Operating Expenses		480,926			456,109			1,190,193			1,205,265
OPERATING INCOME		305,216			346,225			504,936			545,900
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $1,520, $1,528, $4,763 and $4,021)	(52,856		)	(51,784		)	(155,758		)	(158,791		)
	Interest income (expense) on regulatory items	(194		)	(1,623		)	(1,177		)	(5,488		)
	AFUDC-equity	1,959			1,833			6,151			4,823
	Other income	1,948			7,096			5,330			14,197
	Other expense	(1,966		)	(2,823		)	(6,200		)	(7,162		)
Total Other Income (Expense)		(51,109		)	(47,301		)	(151,654		)	(152,421		)
Income Before Income Tax Expense		254,107			298,924			353,282			393,479
Income tax expense		89,665			103,754			124,730			137,328
NET INCOME		164,442			195,170			228,552			256,151
Other comprehensive income
Change in compensation retirement benefits liability and amortization
(Net of taxes $(52), $(33), $(156) and $(103))		96			65			290			192
COMPREHENSIVE INCOME		$	164,538		$	195,235		$	228,842		$	256,343
	The accompanying notes are an integral part of the financial statements.

10

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			September 30,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	255,236	$	201,202
	Accounts receivable less allowance for uncollectible accounts:
		2013 - $8,584; 2012 - $7,622	367,365		248,501
	Materials, supplies and fuel, at average cost		70,929		77,675
	Deferred energy costs (Note 4)		68,391		—
	Deferred income taxes		80,062		48,590
	Other current assets		35,984		28,763
Total Current Assets			877,967		604,731
Utility Property:
	Plant in service		8,459,208		8,363,566
	Construction work-in-progress		695,749		567,941
		Total	9,154,957		8,931,507
	Less accumulated provision for depreciation		2,203,320		2,035,322
		Total Utility Property, Net	6,951,637		6,896,185
Investments and other property, net			51,114		49,808
Deferred Charges and Other Assets:
		Deferred energy (Note 4)	84,041		87,072
		Regulatory assets	746,286		804,013
		Regulatory asset for pension plans	131,628		136,682
		Other deferred charges and assets	58,097		62,654
Total Deferred Charges and Other Assets			1,020,052		1,090,421
TOTAL ASSETS			$	8,900,770	$	8,641,145
		(Continued)

11

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

		September 30,			December 31,
		2013			2012
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 5)	$	129,186		$	106,048
	Accounts payable	202,915			201,193
	Accounts payable, affiliated companies	43,800			42,036
	Accrued expenses	63,465			86,433
	Deferred energy (Note 4)	—			86,102
	Other current liabilities	69,479			52,567
Total Current Liabilities		508,845			574,379
Long-term debt (Note 5)		3,103,980			3,230,808
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
	Deferred income taxes	1,257,818			1,101,804
	Deferred investment tax credit	3,857			4,688
	Accrued retirement benefits	52,429			49,381
	Regulatory liabilities	376,136			323,400
	Other deferred credits and liabilities	551,545			434,367
Total Deferred Credits and Other Liabilities		2,241,785			1,913,640
Shareholder's Equity:
	Common stock, $1.00 par value; 1,000 shares authorized
	issued and outstanding for 2013 and 2012	1			1
	Other paid-in capital	2,308,211			2,308,211
	Retained earnings	742,164			618,612
	Accumulated other comprehensive loss	(4,216		)	(4,506		)
Total Shareholder's Equity		3,046,160			2,922,318
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	8,900,770		$	8,641,145
The accompanying notes are an integral part of the financial statements.
(Concluded)

12

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Nine Months Ended
			September 30,
			2013			2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	228,552		$	256,151
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization	207,915			201,096
		Deferred taxes and deferred investment tax credit	126,080			150,289
		AFUDC-equity	(6,151		)	(4,823		)
		Deferred energy	(152,534		)	(7,335		)
		Regulatory disallowance	11,866			—
		Amortization of other regulatory assets	75,893			56,012
		Deferred rate increase	9,241			2,252
		Other, net	(722		)	(35,553		)
	Changes in certain assets and liabilities:
		Accounts receivable	(118,863		)	(164,858		)
		Materials, supplies and fuel	7,017			(5,119		)
		Other current assets	(7,222		)	(3,715		)
		Accounts payable	20,856			53,985
		Accrued retirement benefits	3,048			3,708
		Other current liabilities	(5,819		)	(25,246		)
		Other deferred assets	(1,613		)	(2,412		)
		Other regulatory assets	26			50,008
		Other deferred liabilities	1,613			(10,412		)
Net Cash from Operating Activities			399,183			514,028
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)	(159,063		)	(232,608		)
		Customer advances for construction	1,035			713
		Contributions in aid of construction	20,263			34,274
		Investments and other property - net	1,595			193
Net Cash used by Investing Activities			(136,170		)	(197,428		)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs	(261		)	132,259
		Retirement of long-term debt	(103,718		)	(271,241		)
		Dividends paid	(105,000		)	(119,000		)
Net Cash used by Financing Activities			(208,979		)	(257,982		)
Net Increase in Cash and Cash Equivalents			54,034			58,618
Beginning Balance in Cash and Cash Equivalents			201,202			65,887
Ending Balance in Cash and Cash Equivalents			$	255,236		$	124,505
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	174,050		$	177,459
		Income taxes	$	1		$	1
	Significant non-cash transactions:
		Accrued construction expenses as of September 30,	$	119,943		$	111,052
The accompanying notes are an integral part of the financial statements.

13

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

	Common Stock Shares	Common Stock Amount		Other Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders' Equity
December 31, 2011	1,000	$	1	$	2,308,219	$	544,874		$	(4,117	)	$	2,848,977
Net Income						256,151						256,151
Change in compensation retirement benefits liability and amortization (net of taxes $(103))									192			192
Dividends Declared						(119,000		)				(119,000		)
September 30, 2012	1,000	$	1	$	2,308,219	$	682,025		$	(3,925	)	$	2,986,320
December 31, 2012	1,000	$	1	$	2,308,211	$	618,612		$	(4,506	)	$	2,922,318
Net Income						228,552						228,552
Change in compensation retirement benefits liability and amortization (net of taxes $(156))									290			290
Dividends Declared						(105,000		)				(105,000		)
September 30, 2013	1,000	$	1	$	2,308,211	$	742,164		$	(4,216	)	$	3,046,160
The accompanying notes are an integral part of the financial statements.

14

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
OPERATING REVENUES:
	Electric	$	213,463		$	212,073		$	560,392		$	549,886
	Gas	13,543			12,077			73,480			77,543
Total Operating Revenues		227,006			224,150			633,872			627,429
OPERATING EXPENSES:
	Fuel for power generation	54,827			47,324			141,277			115,137
	Purchased power	33,388			33,999			114,755			98,400
	Gas purchased for resale	7,383			5,382			62,277			46,491
	Deferral of energy - electric - net (Note 4)	(7,925		)	(5,498		)	(44,223		)	(13,854		)
	Deferral of energy - gas - net (Note 4)	(1,964		)	(853		)	(22,315		)	(970		)
	Energy efficiency program costs	2,044			4,092			5,679			11,143
	Regulatory disallowance	5,469			—			5,469			—
	Merger-related costs (Note 2)	2,008			—			5,528			—
	Other operating expenses	34,394			34,128			106,455			104,214
	Maintenance	5,968			6,481			20,956			23,596
	Depreciation and amortization	27,952			27,537			83,772			80,594
	Taxes other than income	5,944			5,894			18,414			17,382
Total Operating Expenses		169,488			158,486			498,044			482,133
OPERATING INCOME		57,518			65,664			135,828			145,296
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $437, $448, $1,007 and $1,458)	(15,122		)	(15,298		)	(46,020		)	(47,650		)
	Interest expense on regulatory items	(87		)	(401		)	53			(715		)
	AFUDC-equity	632			582			1,579			1,843
	Other income	983			1,399			4,641			4,181
	Other expense	(982		)	(998		)	(3,803		)	(3,609		)
Total Other Income (Expense)		(14,576		)	(14,716		)	(43,550		)	(45,950		)
Income Before Income Tax Expense		42,942			50,948			92,278			99,346
Income tax expense		13,691			16,521			30,347			33,596
NET INCOME		29,251			34,427			61,931			65,750
Other comprehensive income
Change in compensation retirement benefits liability and amortization
(Net of taxes $(32), $(22), $(95) and $(68))		59			42			176			127
COMPREHENSIVE INCOME		$	29,310		$	34,469		$	62,107		$	65,877
	The accompanying notes are an integral part of the financial statements.

15

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			September 30,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	84,128	$	60,786
	Accounts receivable less allowance for uncollectible accounts:
		2013 - $1,059; 2012 - $1,126	115,765		124,464
	Materials, supplies and fuel, at average cost		50,770		60,662
	Deferred energy costs (Note 4)		13,844		—
	Intercompany income taxes receivable		10,351		10,351
	Deferred income taxes		49,748		21,589
	Other current assets		12,566		11,633
Total Current Assets			337,172		289,485
Utility Property:
	Plant in service		3,736,104		3,667,487
	Construction work-in-progress		125,681		140,168
		Total	3,861,785		3,807,655
	Less accumulated provision for depreciation		1,323,504		1,277,866
		Total Utility Property, Net	2,538,281		2,529,789
Investments and other property, net			7,126		6,499
Deferred Charges and Other Assets:
		Regulatory assets	301,918		328,755
		Regulatory asset for pension plans	135,257		140,268
		Deferred energy (Note 4)	1,014		—
		Other deferred charges and assets	13,524		21,477
Total Deferred Charges and Other Assets			451,713		490,500
TOTAL ASSETS			$	3,334,292	$	3,316,273
(Continued)

16

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

		September 30,			December 31,
		2013			2012
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 5)	$	271		$	250,235
	Accounts payable	84,277			106,415
	Accounts payable, affiliated companies	21,543			21,534
	Accrued expenses	29,909			32,936
	Deferred energy (Note 4)	—			50,763
	Other current liabilities	18,821			13,655
Total Current Liabilities		154,821			475,538
Long-term debt (Note 5)		1,177,829			928,990
Commitments and Contingencies (Note 8)
Deferred Credits and Other Liabilities:
	Deferred income taxes	525,694			465,508
	Deferred investment tax credit	7,766			8,850
	Accrued retirement benefits	75,133			98,676
	Regulatory liabilities	255,232			227,287
	Other deferred credits and liabilities	76,974			72,688
Total Deferred Credits and Other Liabilities		940,799			873,009
Shareholder's Equity:
	Common stock, $3.75 par value; 20,000,000 shares authorized
	1,000 shares issued and outstanding for 2013 and 2012	4			4
	Other paid-in capital	1,111,266			1,111,266
	Retained deficit	(49,055		)	(70,986		)
	Accumulated other comprehensive loss	(1,372		)	(1,548		)
Total Shareholder's Equity		1,060,843			1,038,736
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	3,334,292		$	3,316,273
	The accompanying notes are an integral part of the financial statements.
	(Concluded)

17

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Nine Months Ended
			September 30,
			2013			2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	61,931		$	65,750
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization	83,772			80,594
		Deferred taxes and deferred investment tax credit	32,847			42,809
		AFUDC-equity	(1,579		)	(1,843		)
		Deferred energy	(65,622		)	(11,367		)
		Regulatory disallowance	5,469			—
		Amortization of other regulatory assets	58,769			58,484
		Other, net	185			(15,532		)
	Changes in certain assets and liabilities:
		Accounts receivable	17,700			13,452
		Materials, supplies and fuel	9,892			(12,915		)
		Other current assets	(934		)	(6,512		)
		Accounts payable	(16,893		)	(21,002		)
		Accrued retirement benefits	(23,544		)	(18,477		)
		Other current liabilities	2,141			(3,522		)
		Other deferred assets	(2,021		)	(1,160		)
		Other regulatory assets	(3,302		)	(15,588		)
		Other deferred liabilities	(1,876		)	(6,282		)
Net Cash from Operating Activities			156,935			146,889
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)	(108,735		)	(155,182		)
		Customer advances for construction	(114		)	(2,221		)
		Contributions in aid of construction	18,451			29,590
		Investments and other property - net	24			24
Net Cash used by Investing Activities			(90,374		)	(127,789		)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs	247,506			(1,447		)
		Retirement of long-term debt	(250,725		)	(1,112		)
		Dividends paid	(40,000		)	(20,000		)
Net Cash used by Financing Activities			(43,219		)	(22,559		)
Net Increase (Decrease) in Cash and Cash Equivalents			23,342			(3,459		)
Beginning Balance in Cash and Cash Equivalents			60,786			55,195
Ending Balance in Cash and Cash Equivalents			$	84,128		$	51,736
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	45,554		$	45,772
	Significant non-cash transactions:
		Accrued construction expenses as of September 30,	$	21,271		$	21,060
The accompanying notes are an integral part of the financial statements.

18

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

	Common Stock Shares	Common Stock Amount		Other Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders' Equity
December 31, 2011	1,000	$	4	$	1,111,262	$	(135,340	)	$	(1,384	)	$	974,542
Net Income						65,750						65,750
Change in compensation retirement benefits liability and amortization (net of taxes $(68))									127			127
Dividends Declared						(20,000		)				(20,000		)
September 30, 2012	1,000	$	4	$	1,111,262	$	(89,590	)	$	(1,257	)	$	1,020,419
December 31, 2012	1,000	$	4	$	1,111,266	$	(70,986	)	$	(1,548	)	$	1,038,736
Net Income						61,931						61,931
Change in compensation retirement benefits liability and amortization (net of taxes $(95))									176			176
Dividends Declared						(40,000		)				(40,000		)
September 30, 2013	1,000	$	4	$	1,111,266	$	(49,055	)	$	(1,372	)	$	1,060,843
The accompanying notes are an integral part of the financial statements.

19

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE1.              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 Company, Inc. and Sierra Gas Holding Company.  All intercompany balances and 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.

In the opinion of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown.  These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in the 2012 Form 10-K.

The results of operations and cash flows of NVE, NPC and SPPC for the nine months ended September 30, 2013, are not necessarily indicative of the results to be expected for the full year.

Accounting Policies

Consolidations of VIEs

To identify potential variable interests, management reviewed 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 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 September 30, 2013, 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.

Recent Accounting Standards Update

Derivatives and Hedging (ASC815) 

In July 2013, the FASB amended its existing guidance related to hedge accounting.  The amendment permits the Fed Funds Effective Swap Rate (OIS) to be used as a U.S benchmark interest rate for hedge accounting purposes under ASC 815, in addition, to the current approved U.S. rates which include interest rates on direct Treasury obligations of the U.S. government (UST) and LIBOR.  The amendment is effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013.    The adoption of this guidance did not have an impact on the presentation of the consolidated financial statements or disclosure requirements for NVE and the Utilities.

Income Taxes (ASC 740)

In July 2013, the FASB amended its existing guidance related to the presentation of an unrecognized tax benefit on the financial statements.  ASC 740, Income Taxes, does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a NOL carryforward, a similar tax loss, or a tax credit carryforward exists.  As a result, there is diversity in practice in the presentation of unrecognized tax benefits.  The objective of the amendment is to eliminate the diversity in practice, requiring the

20

unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward with certain exceptions.  The amendment can be applied prospectively or retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 for public entities.  NVE and the Utilities have elected to early adopt this amendment prospectively as of September 30, 2013, presenting their unrecognized tax benefit as a reduction to their NOL deferred tax asset. The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.

Federal Income Tax Regulations

In September 2013, the Internal Revenue Service and the U.S. Treasury Department released final tax regulations on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014.  NVE and the Utilities continue to evaluate the effects of the tangible property regulations as well as the generation guidance in Revenue Procedure 2013-24, but do not believe that these tax regulations will have a material impact on the presentation of the financial statements for NVE and the Utilities.

Other Comprehensive Income (ASC 220)

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.  In February 2013, the FASB reinstated certain portions of the deferred amendment.  The reinstated amendment is applied prospectively and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance did not have an impact on the presentation of the financial statements for NVE and the Utilities.

Balance Sheet Offsetting Disclosures (ASC 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 includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements.  The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance did not have an impact on the disclosure requirements for NVE and the Utilities.

NOTE 2.      MERGER-RELATED ACTIVITIES

MidAmerican Merger

On May 29, 2013, NVE entered into the MidAmerican Merger Agreement.  The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation.  Once merged, NVE will become an indirect wholly owned subsidiary of MEHC.  The closing is expected to occur in late 2013 or the first quarter of 2014.

Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest and subject to applicable withholding taxes. 

The MidAmerican Merger Agreement has been approved by the BOD of both NVE and MEHC, but the consummation of the MidAmerican Merger is subject to the satisfaction or waiver of specified closing conditions, including:

• the approval of the MidAmerican Merger Agreement by the holders of a majority of the outstanding shares of NVE common stock. On September 25, 2013, NVE’s stockholders approved the MidAmerican Merger Agreement. Consequently, this closing condition has been satisfied;

• the receipt of regulatory approvals and other consents required to consummate the MidAmerican Merger, including, among others, approvals from the PUCN and the FERC on terms and conditions specified in the MidAmerican Merger Agreement (in July 2013, filings were made with the PUCN and FERC. See Note 4, Regulatory Actions, for further details of these filings);

• the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. On July 22, 2013, NVE was advised that the Department of Justice and the U.S. Federal Trade Commission

21

had terminated the applicable waiting period under the Hart-Scott-Rodino Act.  Consequently, the closing condition with respect to the Hart-Scott-Rodino Act has been satisfied;

• the absence of the occurrence of a company material adverse effect (as defined in the MidAmerican Merger Agreement) after the date of the MidAmerican Merger Agreement; and

• other customary closing conditions.

The MidAmerican Merger Agreement contains customary representations, warranties and covenants for both NVE and MEHC. These covenants include an obligation for us, subject to certain exceptions, to conduct our business in a manner substantially consistent with our current practice. In addition, the covenants contain several restrictions that apply unless MEHC’s consent is received, including limitations on making certain business acquisitions, limitations on our total capital spending, limitations on the extent to which we may obtain financing through long-term debt or equity issuances and limitations on increasing our common stock dividend payout. 

The MidAmerican Merger Agreement contains certain termination rights and fees for both NVE and MEHC. In the event of termination of the MidAmerican Merger under certain circumstances, NVE may be obligated to pay MEHC a termination fee of up to $169.7 million.

During the three and nine month periods ending September 30, 2013, NVE incurred $7.9 million (pre-tax) and $21.4 million (pre-tax) of merger-related fees and stock compensation costs related to the MidAmerican Merger which have been expensed and presented on the Statement of Comprehensive Income as Merger-Related Costs.  Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation, upon announcement of the MidAmerican Merger.  NVE expects to incur additional merger fees relating to the MidAmerican Merger upon consummation of the MidAmerican Merger.

As a result of the pending MidAmerican Merger, NVE, its directors, Silver Merger Sub, Inc. and, in some cases, MEHC, have been named as defendants in certain lawsuits brought by alleged NVE shareholders seeking, among other things, to enjoin the proposed MidAmerican Merger; see Note 8, Commitments and Contingencies for further details.  In addition, NVE has ceased the repurchase of any common stock for NVE stock compensation plans; see Note 10, Common Stock and Other Paid-In Capital. 

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination.  The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities.  As a result, NVE, NPC and SPPC will be required to offer to purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers.  The average interest rate under these debt securities is approximately 6.25%, 6.42% and 5.51% for NVE, NPC and SPPC, respectively.  To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities’ revolving credit facilities or the issuance of long-term debt. Furthermore, NVE and the Utilities were required to obtain consents from lenders under the terms of the Utilities’ revolving credit facilities and NVE’s Term Loan before consummating the MidAmerican Merger. In November 2013, NVE amended its Term Loan and NPC and SPPC amended their revolving credit facilities, in each case to permit the MidAmerican Merger.

One Company Merger between NPC and SPPC

As detailed further in Note 4, Regulatory Actions, NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC.   The One Company Merger is subject to approval by the PUCN and FERC.

NOTE 3.            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

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margin, which the Utilities calculate as operating revenues less energy costs, energy efficiency program costs and regulatory disallowances provides a measure of income available to support the other operating expenses of the Utilities.  See Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements in the 2012 Form 10-K for further information regarding energy efficiency program costs.  

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

Three Months Ended
September 30, 2013
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	1,013,151		$	3		$	786,142		$	227,006		$	213,463		$	13,543
Energy Costs:
Fuel for power generation	217,954			—			163,127			54,827			54,827			—
Purchased power	205,970			—			172,582			33,388			33,388			—
Gas purchased for resale	7,383			—			—			7,383			—			7,383
Deferred energy	(55,270		)	—			(45,381		)	(9,889		)	(7,925		)	(1,964		)
Energy efficiency program costs	16,042			—			13,998			2,044			2,044			—
Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
Total Costs	$	409,414		$	—		$	316,192		$	93,222		$	87,803		$	5,419
Gross Margin	$	603,737		$	3		$	469,950		$	133,784		$	125,660		$	8,124
Merger-related costs	7,857			229			5,620			2,008
Other operating expenses	106,068			830			70,844			34,394
Maintenance	17,176			—			11,208			5,968
Depreciation and amortization	96,801			—			68,849			27,952
Taxes other than income	14,214			57			8,213			5,944
Operating Income (Loss)	$	361,621		$	(1,113	)	$	305,216		$	57,518

Nine Months Ended
September 30, 2013
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	2,329,011		$	10		$	1,695,129		$	633,872		$	560,392		$	73,480
Energy Costs:
Fuel for power generation	554,181			—			412,904			141,277			141,277			—
Purchased power	498,141			—			383,386			114,755			114,755			—
Gas purchased for resale	62,277			—			—			62,277			—			62,277
Deferred energy	(221,022		)	—			(154,484		)	(66,538		)	(44,223		)	(22,315		)
Energy efficiency program costs	38,486			—			32,807			5,679			5,679			—
Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
Total Costs	$	949,398		$	—		$	686,479		$	262,919		$	222,957		$	39,962
Gross Margin	$	1,379,613		$	10		$	1,008,650		$	370,953		$	337,435		$	33,518
Merger-related costs	21,409			1,394			14,487			5,528
Other operating expenses	317,538			2,747			208,336			106,455
Maintenance	66,128			—			45,172			20,956
Depreciation and amortization	291,687			—			207,915			83,772
Taxes other than income	46,536			318			27,804			18,414
Operating Income (Loss)	$	636,315		$	(4,449	)	$	504,936		$	135,828

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Three Months Ended
September 30, 2012
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	1,026,488		$	4		$	802,334		$	224,150		$	212,073		$	12,077
Energy Costs:
Fuel for power generation	171,316			—			123,992			47,324			47,324			—
Purchased power	205,686			—			171,687			33,999			33,999			—
Gas purchased for resale	5,382			—			—			5,382			—			5,382
Deferred energy	(29,036		)	—			(22,685		)	(6,351		)	(5,498		)	(853		)
Energy efficiency program costs	32,584			—			28,492			4,092			4,092			—
Total Costs	$	385,932		$	—		$	301,486		$	84,446		$	79,917		$	4,529
Gross Margin	$	640,556		$	4		$	500,848		$	139,704		$	132,156		$	7,548
Other operating expenses	100,108			608			65,372			34,128
Maintenance	19,014			—			12,533			6,481
Depreciation and amortization	94,512			—			66,975			27,537
Taxes other than income	15,682			45			9,743			5,894
Operating Income (Loss)	$	411,240		$	(649	)	$	346,225		$	65,664

Nine Months Ended
September 30, 2012
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	2,378,606		$	12		$	1,751,165		$	627,429		$	549,886		$	77,543
Energy Costs:
Fuel for power generation	400,936			—			285,799			115,137			115,137			—
Purchased power	486,894			—			388,494			98,400			98,400			—
Gas purchased for resale	46,491			—			—			46,491			—			46,491
Deferred Energy	(30,285		)	—			(15,461		)	(14,824		)	(13,854		)	(970		)
Energy efficiency program costs	76,609			—			65,466			11,143			11,143			—
Total Costs	$	980,645		$	—		$	724,298		$	256,347		$	210,826		$	45,521
Gross Margin	$	1,397,961		$	12		$	1,026,867		$	371,082		$	339,060		$	32,022
Other operating expenses	307,080			2,382			200,484			104,214
Maintenance	76,190			—			52,594			23,596
Depreciation and amortization	281,690			—			201,096			80,594
Taxes other than income	44,457			282			26,793			17,382
Operating Income (Loss)	$	688,544		$	(2,652	)	$	545,900		$	145,296

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NOTE 4.    REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy amounts were included in the consolidated balance sheets as of September 30, 2013 (dollars in thousands):

	September 30, 2013
	NVE Total			NPC Electric			SPPC Electric			SPPC Gas
Deferred Energy
Cumulative Deferred Balance authorized in 2013 DEAA	$	(152,990	)	$	(102,227	)	$	(32,693	)	$	(18,070	)
2013 Amortization	111,977			69,288			23,695			18,994
2013 Deferred Energy Under Collections (1)	118,397			95,465			19,697			3,235
Deferred Energy Balance at September 30, 2013 - Subtotal	$	77,384		$	62,526		$	10,699		$	4,159
Reinstatement of deferred energy (effective 6/07, 10 years)	89,906			89,906			—			—
Total Deferred Energy	$	167,290		$	152,432		$	10,699		$	4,159
Current Assets
Deferred energy	$	82,235		$	68,391		$	10,322		$	3,522
Non-current Assets
Deferred energy	85,055			84,041			377			637
Total Net Deferred Energy	$	167,290		$	152,432		$	10,699		$	4,159

⁽¹⁾  These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting Policies, Deferred Energy Accounting, of the Notes to the Financial Statements in the 2012 Form 10-K.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Joint Application for the merger between NVE and MEHC (MidAmerican Merger)

In July 2013, NVE and MEHC filed a joint application with the PUCN seeking the authorization of the MidAmerican Merger. Under Nevada law, the PUCN may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “in the public interest”.  If the PUCN does not issue a final order regarding the MidAmerican Merger within 180 days of the application filing date, the transaction will be deemed to be authorized.  Based on the date of filing, the expected authorization date for the joint application between NVE and MEHC is January 2014.  Hearings are scheduled for November 2013.

Joint Application of NPC and SPPC (One Company Merger Filing)

                In May 2013, NPC and SPPC filed a joint application with the PUCN to consolidate the Utilities into a single jurisdictional utility.  The joint application with the PUCN requested the following:

• Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC’s assets and obligations to NPC, and renaming the surviving utility NVEOC;

• Authority to transfer SPPC’s certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC’s CPCN to reflect the name of the surviving utility, NVEOC; and

• Authority to transfer all SPPC’s electric and gas utility assets, including electric generation assets, to NPC.

The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.”  The PUCN is not bound by any statutory deadlines with respect to this application. Hearings were expected to begin in February 2014, but the Utilities are seeking to delay the proceedings to the second half of 2014. 

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Financing Application

                Concurrent with the One Company Merger filing, NPC and SPPC filed a joint financing application with the PUCN.  The application requested the PUCN to restate and review the Utilities’ existing unused authority and to assign and consolidate the unused authority under NVEOC.  In addition, the application requests new authority of $705.0 million.  The consolidated authority would give NVEOC authority to issue new debt of $1.1 billion and authority to refinance or redeem debt of $1.5 billion. The application does not seek a change to NPC’s and SPPC’s existing revolving credit facility authority of $1.3 billion and $600 million, respectively.   The Utilities have requested that the financing application be consolidated with the One Company Merger filing.  However, as the One Company Merger will not be approved prior to the December 31, 2013 expiration of NPC’s current financing authority, NPC requested that its current authority be extended, as well as additional authority to refinance debt of $255 million.  In September 2013, the PUCN accepted a stipulation extending NPC’s existing financing authority until an order is issued in the One Company Merger filing.

Nevada Power Company

NPC 2013 DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEIR and EEPR rate elements.  In September 2013, the PUCN issued an order disallowing approximately $1.1 million (pre-tax) in deferred energy costs, which NPC expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013 and correspondingly adjusted the deferred energy balance as reflected in the table above. In addition, the PUCN indicated in their order that EEIR revenue should not contribute to the Utilities earning more than their authorized ROR. As NPC earned in excess of its authorized ROR in 2012, the PUCN disallowed approximately $10.8 million in pre-tax EEIR revenues (including carrying charges) which was expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013. Furthermore, as a result of this order and NPC’s estimated 2013 ROR calculated to be in excess of its authorized ROR, NPC has recorded a provision for refund of $11.2 million pre-tax against operating revenues, representing all EEIR revenues recorded during the nine months ended September 30, 2013. The September PUCN order includes the following changes in revenue requirement (dollars in millions):

	Effective Date	Authorized Revenue Requirement			Present Revenue Requirement		$ Change in Revenue Requirement
Revenue Requirement Subject To Change:
REPR (1)	Oct. 2013	$	28.4		$	38.7	$	(10.3	)
TRED (1)	Oct. 2013	15.7			15.9		(0.2		)
EEPR Base (1)	Oct. 2013	45.9			32.6		13.3
EEPR Amortization (1)	Oct. 2013	(29.9		)	9.0		(38.9		)
EEIR Base (2)	Oct. 2013	15.1			10.6		4.5
EEIR Amortization (3)	Oct. 2013	(17.2		)	10.7		(27.9		)
Total Revenue Requirement		$	58.0		$	117.5	$	(59.5	)

⁽¹⁾  Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income.

⁽²⁾  The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if NPC earns in excess of its authorized ROR. In future periods, NPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

⁽³⁾  Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.

Sierra Pacific Power Company

  SPPC Electric General Rate Case

In June 2013, SPPC filed its statutorily required GRC for its Nevada electric operations and updated the filing in August 2013.  In the updated filing, SPPC is requesting the following:

• Decrease in general rates by $4.7 million, approximately a 0.7% decrease; and

• ROE and ROR of 10.4% and 7.74%, respectively.

Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014. 

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SPPC Gas General Rate Case

In June 2013, SPPC filed a GRC for its gas operations and updated the filing in August 2013.  In the updated filing, SPPC is requesting the following:

• Increase in general rates by $6.0 million, approximately a 6.1% increase; and

• ROE and ROR of 10.35% and 7.72%, respectively.

Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014.

SPPC 2013 Electric DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEPR and EEIR rate elements. In September 2013, the PUCN issued an order disallowing approximately $0.1 million (pre-tax) in deferred energy costs, which SPPC expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013 and correspondingly adjusted the deferred energy balance as reflected in the table above. In addition, with respect to the EEIR disallowance discussed above under NPC, the PUCN disallowed $5.5 million (pre-tax) of SPPC's 2012 EEIR revenues, (including carrying charges) as a result of earning in excess of its authorized ROR. As a result $5.5 million was expensed as a regulatory disallowance for the three and nine months ended September 30, 2013. Also, similar to NPC, SPPC’s estimated 2013 ROR is calculated to be in excess of its authorized ROR, as such, SPPC has recorded a provision for refund of $4.0 million pre-tax against operating revenues, representing all EEIR revenues recorded during the nine months ended September 30, 2013. The September PUCN order includes the following changes in revenue requirement (dollars in millions):

	Effective Date	Authorized Revenue Requirement			Present Revenue Requirement		$ Change in Revenue Requirement
Revenue Requirement Subject To Change:
REPR (1)	Oct. 2013	$	42.3		$	44.4	$	(2.1	)
TRED (1)	Oct. 2013	7.4			6.3		1.1
EEPR Base (1)	Oct. 2013	6.0			5.6		0.4
EEPR Amortization (1)	Oct. 2013	(2.1		)	1.8		(3.9		)
EEIR Base (2)	Oct. 2013	5.5			4.7		0.8
EEIR Amortization (3)	Oct. 2013	(3.7		)	1.9		(5.6		)
Total Revenue Requirement		$	55.4		$	64.7	$	(9.3	)

⁽¹⁾ Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income.

⁽²⁾ The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if SPPC earns in excess of its authorized ROR. In future periods, SPPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

⁽³⁾ Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.

SPPC 2013 Nevada Gas DEAA and REPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ended December 31, 2012 and to reset the REPR.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above.  In September 2013, the PUCN issued an order resulting in an overall decrease in revenue requirement of $0.2 million.

FERC Matters

NPC

NPC 2012 FERC Transmission Rate Case

In October 2012, NPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2003.  In December 2012, FERC issued an order which suspended the proposed rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013.  All rates are currently subject to refund and final approval by the FERC.  However, at this time management is unable to determine the final revenue impact of the case.

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SPPC

SPPC 2012 FERC Transmission Rate Case

In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003, respectively.  In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013. On June 17, 2013, SPPC filed an unopposed settlement agreement resolving all issues with the FERC, for approval for rates effective June 1, 2013.    FERC approved the settlement on August 29, 2013. The rate changes under the terms of the settlement agreement are expected to result in an overall annual revenue increase of $1.5 million.

NVE, NPC and SPPC

2013 FERC Transmission Rate Case

In May 2013, NPC and SPPC filed an application with the FERC to reset transmission and ancillary service rates effective on the later of January 1, 2014, or the ON Line in-service date.  The rate changes reflect the addition of the ON Line in the transmission revenue requirement.  Various intervenors filed protests and NPC and SPPC filed a response to those protests on July 16, 2013.  On August 5, 2013, FERC issued an order which suspended the rate changes until January 1, 2014 or the in-service date for ON Line, subject to refund. On August 12, 2013 the FERC designated a Settlement Judge and the matter is now in settlement proceedings.  At this time, management is unable to determine the final revenue impact of the case.

FERC One Company Merger Request

In May 2013, NVE, NPC and SPPC filed an application with the FERC under Section 203 of the Federal Power Act for Approval of Internal Reorganization.  In their request, NPC and SPPC requested FERC authorization for an internal corporate reorganization under which SPPC will merge into NPC and the surviving entity will be renamed NVEOC.  On October 21, 2013, NVE, NPC and SPPC submitted an informational filing with FERC indicating that given the status of an application pending before the PUCN, the applicants did not object to FERC deferring its consideration of the application. The application remains pending before FERC for consideration.  

FERC MidAmerican Merger Request

On July 12, 2013, an application was filed with the FERC under Section 203 of the Federal Power Act, to approve the MidAmerican Merger.  The MidAmerican Merger is discussed in more detail in Note 2, Merger-Related Activities.   Under Section 203 of the Federal Power Act, the FERC may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “consistent with the public interest”.  If the FERC does not grant or deny the application within 180 days after the application was filed, the application is deemed granted unless the FERC finds that further consideration, for a period not to exceed an additional 180 days, is required to determine whether the transaction meets the specified standards.  The application requests authorization of the proposed transaction by December 19, 2013; however, NVE is unable to determine the timing of a decision in the filing.

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NOTE 5.    LONG-TERM DEBT

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

				September 30,											December 31,
				2013											2012
Long-Term Debt:	Stated Rate		Maturity Date	Consolidated			NVE Holding Co.		NPC			SPPC			Consolidated			NVE Holding Co.		NPC			SPPC
Secured Debt
General and Refunding Mortgage Securities
NPC Series L	5.875	%	2015	$	250,000		$	—	$	250,000		$	—		$	250,000		$	—	$	250,000		$	—
NPC Series M	5.950	%	2016	210,000			—		210,000			—			210,000			—		210,000			—
NPC Series N	6.650	%	2036	370,000			—		370,000			—			370,000			—		370,000			—
NPC Series O	6.500	%	2018	325,000			—		325,000			—			325,000			—		325,000			—
NPC Series R	6.750	%	2037	350,000			—		350,000			—			350,000			—		350,000			—
NPC Series S	6.500	%	2018	500,000			—		500,000			—			500,000			—		500,000			—
NPC Series U	7.375	%	2014	125,000			—		125,000			—			125,000			—		125,000			—
NPC Series V	7.125	%	2019	500,000			—		500,000			—			500,000			—		500,000			—
NPC Series X	5.375	%	2040	250,000			—		250,000			—			250,000			—		250,000			—
NPC Series Y	5.450	%	2041	250,000			—		250,000			—			250,000			—		250,000			—
SPPC Series M	6.000	%	2016	450,000			—		—			450,000			450,000			—		—			450,000
SPPC Series P	6.750	%	2037	251,742			—		—			251,742			251,742			—		—			251,742
SPPC Series Q	5.450	%	2013	—			—		—			—			250,000			—		—			250,000
SPPC Series T	3.375	%	2023	250,000			—		—			250,000			—			—		—			—
Variable Rate Debt (Secured by General and Refunding Mortgage Securities)
NPC IDRB Series 2000A			2020	—			—		—			—			98,100			—		98,100			—
NPC PCRB Series 2006			2036	37,700			—		37,700			—			37,700			—		37,700			—
NPC PCRB Series 2006A			2032	37,975			—		37,975			—			37,975			—		37,975			—
SPPC PCRB Series 2006A			2031	58,200			—		—			58,200			58,200			—		—			58,200
SPPC PCRB Series 2006B			2036	75,000			—		—			75,000			75,000			—		—			75,000
SPPC PCRB Series 2006C			2036	81,475			—		—			81,475			81,475			—		—			81,475
Senior Notes
NVE Senior Notes	6.250	%	2020	315,000			315,000		—			—			315,000			315,000		—			—
NVE Term Loan	2.560	%	2014	195,000			195,000		—			—			195,000			195,000		—			—
Obligations under capital leases				38,415			—		36,571			1,844			44,258			—		42,908			1,350
Unamortized bond premium and discount (net)				759			—		(9,080		)	9,839			1,631			—		(9,827		)	11,458
Current maturities				(129,457		)	—		(129,186		)	(271		)	(356,283		)	—		(106,048		)	(250,235		)
Total Long-Term Debt				$	4,791,809		$	510,000	$	3,103,980		$	1,177,829		$	4,669,798		$	510,000	$	3,230,808		$	928,990

Substantially all utility plant is subject to the liens of the NPC Indenture and the SPPC Indenture under which their respective General and Refunding Mortgage Securities are issued.

Financing Transactions

Nevada Power Company

 In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A.  In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.  

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Sierra Pacific Power Company

In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand, to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013. 

NOTE 6.     FAIR VALUE OF FINANCIAL INSTRUMENTS

The September 30, 2013 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments. As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2012 Form 10-K, investments held in Rabbi Trust continues to be considered Level 1 in the fair value hierarchy.

The total fair value of NVE’s consolidated long-term debt at September 30, 2013, is estimated to be $5.6 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 $5.9 billion as of December 31, 2012.

The total fair value of NPC’s consolidated long-term debt at September 30, 2013, is estimated to be $3.7 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 $4.1 billion at December 31, 2012.

The total fair value of SPPC’s consolidated long-term debt at September 30, 2013, 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, 2012.

NOTE 7.    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 post-retirement 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 post-retirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees. A summary of the components of net periodic pension and other post-retirement costs for the three and nine months ended September 30 follows. This summary is based on a December 31, measurement date (dollars in thousands):

NVE
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	5,132		$	4,406		$	660		$	595
Interest cost	9,303			10,228			1,677			1,905
Expected return on plan assets	(12,708		)	(12,447		)	(1,687		)	(1,563		)
Amortization of prior service cost	(720		)	(724		)	(952		)	(987		)
Amortization of net loss	4,797			3,473			890			731
Net periodic benefit cost	$	5,804		$	4,936		$	588		$	681

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	15,396		$	13,220		$	1,980		$	1,787
Interest cost	27,911			30,684			5,030			5,715
Expected return on plan assets	(38,124		)	(37,341		)	(5,060		)	(4,690		)
Amortization of prior service cost	(2,162		)	(2,173		)	(2,857		)	(2,961		)
Amortization of net loss	14,391			10,418			2,671			2,193
Net periodic benefit cost	$	17,412		$	14,808		$	1,764		$	2,044

The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 34.5% and 35.0% respectively.

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NPC
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	2,761		$	2,358		$	389		$	350
Interest cost	4,453			4,881			556			602
Expected return on plan assets	(6,270		)	(6,237		)	(631		)	(592		)
Amortization of prior service cost	(453		)	(456		)	(23		)	229
Amortization of net loss	2,117			1,363			289			221
Net periodic benefit cost	$	2,608		$	1,909		$	580		$	810

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	8,283		$	7,072		$	1,167		$	1,050
Interest cost	13,358			14,643			1,667			1,807
Expected return on plan assets	(18,810		)	(18,711		)	(1,892		)	(1,775		)
Amortization of prior service cost	(1,358		)	(1,367		)	(69		)	687
Amortization of net loss	6,351			4,089			867			662
Net periodic benefit cost	$	7,824		$	5,726		$	1,740		$	2,431

The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.9% and 36.9% respectively.

SPPC
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	1,926		$	1,695		$	251		$	227
Interest cost	4,558			5,043			1,104			1,283
Expected return on plan assets	(6,162		)	(5,937		)	(1,022		)	(941		)
Amortization of prior service cost	(277		)	(277		)	(933		)	(1,220		)
Amortization of net loss	2,501			2,026			592			504
Net periodic benefit cost	$	2,546		$	2,550		$	(8	)	$	(147	)

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	5,778		$	5,086		$	752		$	682
Interest cost	13,676			15,130			3,310			3,848
Expected return on plan assets	(18,486		)	(17,813		)	(3,065		)	(2,823		)
Amortization of prior service cost	(831		)	(831		)	(2,798		)	(3,658		)
Amortization of net loss	7,502			6,078			1,777			1,511
Net periodic benefit cost	$	7,639		$	7,650		$	(24	)	$	(440	)

The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 and was 35.6% and 35.1%, respectively.

As discussed in Note 10, Retirement Plan and Post-Retirement Benefits, of the Notes to Financial Statements in the 2012 Form 10-K, NVE offered a voluntary lump sum pension pay out to former employees not currently of retirement age but eligible for future benefits and certain retiree participants already receiving benefits under NVE’s pension plan in an effort to reduce NVE’s future pension obligation. During the nine months ended September 30, 2013, NVE paid $21.5 million in lump sum pension pay outs from the pension assets. The company does not expect any further material amounts to be paid in 2013.

During the nine months ended September 30, 2013 and 2012, the company made contributions to the pension plan in the amount of $20.0 million and $15.0 million, respectively and $5.0 million and $7.1 million, respectively in contributions to the other post-retirement benefits plan. At the present time, it is not anticipated that additional funding will be required for either plan in 2013 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding. The amounts to be contributed in 2013 may change subject to market conditions.

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NOTE 8.             COMMITMENTS AND CONTINGENCIES     

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 $4 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs.  The site is under contract for sale to a third party and the sale is expected to close in the fourth quarter of 2013.   The sale will not be material to NPC.

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 1-4, with the interest of CDWR in Unit 4 having been terminated in October 2013.  The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant.  NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request.  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.

    NPC and SPPC

NVision and SB 123

NVision is a comprehensive plan of NVE for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and other electric generating plants.  NVision includes the following significant details:

• Accelerating the plan to retire 800 MWs of coal plants, starting as soon as December 31, 2014;

• Replacement of such coal plants with the procurement of 300 MWs from renewable facilities;

• Construction or acquisition and ownership of 50 MWs of electric generating capacity from renewable facilities;

• Construction or acquisition and ownership of 550 MWs of electric generating capacity from other electric generating plants; and

• Assuring regulatory procedures that protect reliability and supply and address financial impacts on customer and utility.

In June 2013, the Nevada State Legislature passed SB 123, which was supported by NVE as part of its NVision initiative and includes the requirements as outlined in the bullets above.  The Utilities, along with other interested parties, are currently working with the PUCN to finalize the rulemaking associated with this bill and expect to file an emissions reduction plan in 2014 to specifically address the plan details as outlined above.

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Greenhouse Gas/Carbon Regulations

In conjunction with the release of President Obama’s Climate Action Plan on June 25, 2013, the President issued a memorandum directing the EPA to take several actions on carbon emissions standards for power plants.  As discussed above, NVision and the passage of SB 123, will yield substantial reductions in carbon as NVE and the Utilities retire their existing coal-fired generating facilities on an accelerated schedule. While the Utilities currently cannot predict the financial impact or final mandates by President Obama’s Climate Action Plan or the EPA’s final rules, NVE and the Utilities remain committed to taking progressive steps over time to limit the carbon emissions from its generation fleet by retiring older fossil units and replacing them with new, lower emissions and/or zero emission sources. 

Regional Haze Rules 

In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.

In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations.  In March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station.  The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015.  In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station units at a later date.  In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP.  For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice.  Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015. On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline for the Reid Gardner Generating Station retrofits so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada.  On March 26, 2013, the EPA granted reconsideration of the compliance date for the BART retrofits for Units 1, 2 and 3 at Reid Gardner Generating Station, proposing to extend the compliance date by 18 months, from January 1, 2015 to June 30, 2016. The EPA held a public hearing on April 29, 2013, to accept written and oral comments on this proposed action and t he comment period for this action closed on May 30, 2013. In August 2013, the EPA announced it was taking final action to extend the date by which Units 1, 2, and 3 at Reid Gardner Generating Station must meet the BART limits to reduce emissions of nitrogen oxides. The final date is now affirmed as June 30, 2016.

NVE continues to work toward finalizing the retrofit designs for the affected BART units.  NVE has received approval from the PUCN 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.  As previously disclosed, NVE and the Utilities intend to file with the PUCN their emissions reduction plan in 2014 detailing how they will address the phased retirement of coal fired assets as required under SB 123.  While the BART requirements specify the installation of SNCR’s on Reid Gardner Generating Station Units 1, 2 and 3, the passage of SB 123 could result in the early retirement of those units prior to the required BART installation deadline, pending the final approval of the PUCN.  Therefore, in 2014, NVE and the Utilities will file an emissions reduction plan. NVE and the Utilities would need to obtain either the PUCN approval to retire those units as soon as the end of 2014 or seek approval for the BART retrofit installation with an alternate retirement date.  Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, including Reid Gardner Generating Station Units 1, 2 and 3, but excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units.  NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.

Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal.  In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule.  NVE has intervened in that lawsuit.  In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station.  NVE has intervened in this lawsuit.  At this time management is unable to determine the likelihood of success by petitioners in these litigation

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matters.  An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned. 

The Navajo Generating Station is also an affected unit under EPA’s Regional Haze Rules. On January 17, 2013, the EPA announced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline for reducing NOx emissions. NVE, along with the other owners of the facility, have been reviewing the EPA proposal to determine its impact on the viability of the plant’s future operations. The land lease for the Navajo Generating Station is up for renewal in 2019.  Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations.  It is believed that the EPA BART proposal will require an investment of up to $1.1 billion in additional emission controls at the plant of which NPC’s ownership share is 11.3%.

The original comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested and was granted several extensions, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners. 

On September 25, 2013, the EPA issued a supplemental proposal which included a BART alternative called the Technical Work Group (“TWG”) Alternative. The TWG Alternative is based upon the proposal submitted to the EPA in July 2013 by a group of Navajo Generating Station stakeholders called the TWG. At this time, the EPA is concurrently accepting comments on the BART determination and the EPA Alternative which were proposed in February 2013, as well the TWG Alternative proposed in the supplemental proposal. Comments are now due by January 6, 2014.

Given the uncertainties that remain regarding the various lease and agreement renewal terms, the timeline for BART installation, and the fact that the EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predict at this time the ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take. As a result of the passage of NVision and these uncertainties, NPC expects to file in 2014 an emissions reduction plan to specifically address its ownership participation in the Navajo Generating Station.

Mercury and Air Toxics Standards (MATS)

In December 2011, the EPA signed for publication in the Federal Register a 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 final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia.  The Court has established a schedule for the litigation; however, the Utilities cannot predict the outcome at this time.

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 will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC.  Note that the actual cost will be dependent upon final engineering design.

The three units at the Navajo Generating Station are also subject to MATS. The plant operator intends to file a one year extension request associated with the compliance date in order to allow for additional testing of various mercury control strategies.  Due to the uncertainty of what control equipment will be ultimately required to control mercury from the Navajo Generating Station units, a cost estimate is unable to be determined at this time.

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.

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Other Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.  In addition, NVE and the Utilities may also be subject to future state or federal regulations.  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, which may be accelerated by any decision to retire a generating station or other facility.  If remediation activities involve statutory joint and several liability provisions, strict liability or cost recovery of 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 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.

In 2008, NPC signed an Administrative Order of Consent (AOC) as owner and operator of Reid Gardner Generating Station Units 1, 2 and 3 and as co-owner and operating agent of Unit 4.  In October 2013, NPC purchased Unit 4 from CDWR. Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs.  However, actual costs of work under the AOC may vary significantly once the scope of work is defined and additional site characterization has been completed.

NVE and the Utilities seek to continually comply with environmental regulations; however, given the uncertainties involved in the federal, state and local regulatory environment, future costs to comply may be material.

Litigation Contingencies

NVE

Litigation Related to the MidAmerican Merger

Following the announcement of the proposed acquisition of NVE by MEHC through its subsidiary Silver Merger Sub, Inc. on May 29, 2013, several complaints were filed by alleged NVE shareholders in the Eighth Judicial District Court in Clark County, Nevada, challenging the MidAmerican Merger.

On June 6, 2013, a complaint was filed on behalf of a putative class of NVE public shareholders, naming NVE, its BOD, and Silver Merger Sub, Inc., as defendants. This complaint was amended on July 16, 2013.  The amended complaint generally alleges that the individual defendants breached their fiduciary duties in connection with the proposed MidAmerican Merger, including by approving the transaction on allegedly unfair terms, at an allegedly unfair price and pursuant to an allegedly inadequate process; allegedly acting with conflicts and in their own personal interests rather than those of shareholders; and making inadequate disclosures in connection with requested shareholder approval of the proposed MidAmerican Merger.  The amended complaint also alleges that Silver Merger Sub. Inc., NVE and MEHC aided and abetted the individual defendants in breaching their fiduciary duties. 

Four additional complaints were filed in the Eighth Judicial District Court in Clark County, Nevada on June 7, 2013, June 10, 2013, July 12, 2013 and August 16, 2013.  These complaints contain claims and allegations similar to the amended July 16, 2013 complaint and seek similar relief on behalf of the same putative class. Onecomplaint was voluntarily dismissed. The remaining cases were consolidated in Department XI of the Eighth Judicial District Court in Clark County, Nevada.

An agreement-in-principle has been reached between the parties to these lawsuits, which was memorialized in a memorandum of understanding executed on September 4, 2013.  The memorandum of understanding called for NVE to supplement the proxy statement for the special meeting of stockholders related to the MidAmerican Merger, and the supplemental information was in fact provided via NVE’s Form 8-K dated September 9, 2013. The parties currently are preparing a final stipulation of settlement which will be submitted to the court for approval. It is not known at this time when the court will set hearings and/or issue a final order, but NVE does not expect the outcome of this litigation or settlement to delay the closing of the MidAmerican Merger or otherwise have a material impact on NVE.

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NPC 

Peabody Western Coal Company - Royalty Claim

NPC owns an 11% interest in the Navajo Generating Station, which is located in northern Arizona and 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 June 1999, the Navajo Nation filed suit against Salt River, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”).  NPC was 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 asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process.  The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.

In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit.  In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible re-filing.

In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement among the Navajo Nation, Peabody, Salt River and SCE.  At the request of Salt River, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station. 

SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station.  In October 2013, NPC settled with SCE on this matter.  The terms of the settlement are not material to NPC.

November 2005 Land Investors

In 2006, November 2005 Land Investors, LLC (“NLI”) purchased from the U.S. through the Bureau of Land Management (“BLM”) 2,675 acres of land located in North Las Vegas, Nevada. A small portion of the land was and is traversed by a 500kV transmission line owned by NPC and sited pursuant to a pre-existing right-of-way grant (“Grant”) from the BLM. Subsequent to NLI’s purchase, a dispute arose as to whether NPC owed rent and, if it did, the amount owed to NLI under the Grant. NLI eventually “terminated” the Grant and brought claims against NPC for breach of contract, inverse condemnation and trespass. NPC counterclaimed for express condemnation of a perpetual easement over the right-of-way corridor. The matter proceeded to trial in the Eighth Judicial District Court, Clark County, Nevada. In September 2013, the court awarded NLI approximately $1.0 million for unpaid rent and $5.1 million for inverse condemnation, plus interest and attorneys’ fees. The court also found NPC was entitled to judgment in its favor on its counterclaim for condemnation of the right-of-way corridor.

NPC has appealed to the Nevada Supreme Court, which has yet to establish a schedule for the appeal. Management cannot assess or predict the outcome of the case at this time, but it is not expected to be material to NPC.

SPPC

Farad Dam

In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million.  One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume.  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.  The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.

SPPC filed a claim with the Farad Dam’s insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers.  The insurers contested the extent and amount of insurance coverage.  Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.

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In July 2012, the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC’s right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost.  In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three years time to rebuild to start at the conclusion of all litigation.

The District Court has now set the briefing schedule for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC.

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 Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE’s future lease payments are adjusted for final capital costs, for which the Utilities expect to get regulatory recovery. 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, as of September 30, 2013, capitalized construction costs associated with GBT’s 75% interest of $370.8 million and $19.4 million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.

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NOTE 9.     EARNINGS PER SHARE (NVE)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan. 

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Basic EPS
Numerator ($000)
Net Income	$	187,234	$	223,170	$	271,942	$	304,782
Denominator
Weighted average number of common shares outstanding	235,578,310		235,961,402		235,421,933		235,986,874
Per Share Amounts
Net Income per share - basic	$	0.79	$	0.95	$	1.16	$	1.29
Diluted EPS
Numerator ($000)
Net Income	$	187,234	$	223,170	$	271,942	$	304,782
Denominator(1)
Weighted average number of shares outstanding before dilution	235,578,310		235,961,402		235,421,933		235,986,874
Stock options	61,927		39,256		46,537		37,592
Non-Employee Director stock plan	190,705		166,829		185,337		160,257
Employee stock purchase plan	4,149		6,742		5,831		6,785
Restricted Shares	412,000		584,750		487,667		533,750
Performance Shares	1,358,423		1,362,753		1,191,734		1,125,272
Diluted Weighted Average Number of Shares	237,605,514		238,121,732		237,339,039		237,850,530
Per Share Amounts
Net income per share - diluted	$	0.79	$	0.94	$	1.15	$	1.28

(1) The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending September 30, 2012.  If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

NOTE 10.  COMMON STOCK AND OTHER PAID-IN CAPITAL

Dividends

The following dividend declarations were made by the BOD of NVE:

Declaration Date	Amount	Payable Date	Shareholders of Record Date
February 7, 2013	$0.19	March 20, 2013	March 5, 2013
May 8, 2013	$0.19	June 19, 2013	June 4, 2013
August 1, 2013	$0.19	September 18, 2013	September 3, 2013
November 6, 2013	$0.19	December 18, 2013	December 3, 2013

On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively. For the nine months ended September 30, 2013, NPC and SPPC paid dividends to NVE of $105.0 million and $40.0 million, respectively.

Treasury Stock

NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program.  All shares repurchased are held as treasury stock and may be reissued upon exercise or settlement of the stock compensation award.  Treasury stock is accounted for using the cost method. During the nine months ended September 30, 2013, NVE repurchased 325,178 shares of common stock for approximately $6.3 million.  During the nine months ended September 30, 2013, NVE re-issued 827,097 treasury shares to

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satisfy employee benefit plans.  In May 2013, NVE ceased the repurchase of common stock as a result of the proposed MidAmerican Merger. 

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ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS

OF OPERATIONS

Forward-Looking Statements and Risk Factors

The information in this Form 10-Q 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:

Risks Related to the Pending MidAmerican Merger

• whether NVE or MEHC will be able to satisfy the remaining closing conditions of the MidAmerican Merger Agreement, including the receipt of regulatory approvals from the PUCN and the FERC on the terms and schedules contemplated by the parties;

• whether an event, effect or change will occur that gives rise to a termination of the MidAmerican Merger;

• whether NVE will experience unanticipated difficulties and/or incur unanticipated expenditures relating to the MidAmerican Merger, and whether the MidAmerican Merger will disrupt current plans and operations and create difficulties in employee retention;

• whether legal proceedings against NVE and others related to the MidAmerican Merger will be successful; and

• the impact of delay or failure to complete the MidAmerican Merger on NVE’s common stock price.

Operational Risks

• economic conditions, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, each of which affect customer growth, customer collections, customer demand and usage patterns;

• changes in customer demand for electricity and gas resulting from variations in the rate of industrial, commercial and residential growth in the Utilities’ service territories, from energy conservation programs, and from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies;

• construction risks, including but not limited to those associated with ON Line, 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, recovery of possible cost overruns, delay of in-service dates, and pollution and environmental damage;

• security breaches of our information technology or supervisory 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; 

• 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 have other adverse effects on our business;

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

• whether the Utilities’ NV Energize systems continue to operate as intended, accurately and timely measure customer energy usage and generate billing information, and whether the Utilities can continue to rely on third-party vendors or contractors to support certain proprietary components of the advanced metering systems;

• 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;

• explosions, fires, accidents, mechanical breakdowns or vandalism that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory, including gas distribution services that the Utilities may rely upon, 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;

• the extent to which NVE or the Utilities incur costs in connection with third-party claims or litigation that are not recoverable through insurance, rates, or from other third parties;

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

• 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; and

• unusual or unanticipated changes in normal business operations of the Utilities, including unusual maintenance or repairs.

Regulatory/Legislative Risks

• unfavorable rulings, penalties and findings by the PUCN in rate or other cases, investigations or proceedings, 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, and unfavorable rulings, penalties or findings by the FERC in rate or other cases, investigations and proceedings with regard to wholesale power sales and transmission services;

• 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, use alternative sources of energy, generate their own electricity, or change the conditions under which they may do so;

• 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; and

• 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.

Environmental Risks

• 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.

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Liquidity and Capital Resources Risks

• 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, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs)  and/or power, or a ratings downgrade;

• 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;

• whether provisions of the Dodd-Frank Act or rules made under the act governing derivative transaction reporting, trading, and clearing or imposing margin or collateral requirements will materially increase the cost, or limit the availability or usefulness, to the Utilities of financial transactions and techniques important in managing risks the Utilities face in the commodity, power and financial markets; 

• 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 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;

• whether NVE's BOD will 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 contained in NVE's and the Utilities' agreements;

• 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; and

• 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 postretirement plans, which can affect future funding obligations, costs and pension and other postretirement plan liabilities.

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 Quarterly Report on Form 10-Q, 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 that are specific 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 such agreements and are subject to more recent developments.

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

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EXECUTIVE OVERVIEW

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

• Critical Accounting Policies and Estimates:

• Recent Pronouncements

• For each of NVE, NPC and SPPC:

• Results of Operations

• Analysis of Cash Flows

• Liquidity and Capital Resources

• Regulatory Proceedings (Utilities)

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

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

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes and customer usage patterns have on demand for electric energy and resources.  NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning.  SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter.  The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term energy supply 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 through rates are essential to the operating and financial performance of the Utilities. 

MidAmerican Merger

In May 2013, NVE entered into the MidAmerican Merger Agreement, which provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation.  Once merged, NVE will become an indirect wholly-owned subsidiary of MEHC, which in turn is a wholly-owned subsidiary of Berkshire Hathaway, Inc.  Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest.  The MidAmerican Merger Agreement is subject to various conditions and is discussed in more detail in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements.   In order to close in late 2013 or the first quarter of 2014, management intends to work diligently to satisfy the conditions as outlined in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements, as well as transitional requirements. 

Overview of Major Factors Affecting Results of Operations

NVE recognized net income of $187.2 million for the three months ended September 30, 2013, compared to $223.2 million for the same period in 2012.  The decrease in net income is primarily due to the following pre-tax items:

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• The PUCN disallowance of EEIR revenue and carrying charges of $16.2 million and the additional provision recorded against 2013 EEIR revenue of $15.1 million and other regulatory disallowances of $1.1 million. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements;

• MidAmerican merger-related costs of $7.9 million as discussed in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements;

• An increase in other operating expense primarily due to an increase in meter software maintenance, and right of way leases, overall generation expenses and wage increases for the IBEW 396 collective bargaining agreement. See the Utilities’ respective Results of Operations for further discussion;

• A decrease in other income primarily due to the gain on sale of telecommunications towers recorded in 2012; and   

• A decrease in gross margin of $4.3 million not including the disallowance and provision discussed above. See the Utilities’ respective Results of Operations for further discussion of gross margin.

These decreases were partially offset by the following pre-tax items:

• A decrease in interest expense on regulatory items primarily due to lower over collected deferred energy and regulatory balances.

NVE recognized net income of $271.9 million for the nine months ended September 30, 2013, compared to $304.8 million for the same period in 2012.  The decrease in net income is primarily due to the following pre-tax items:

• The PUCN disallowance of EEIR revenue and carrying charges of $16.2 million and the additional provision recorded against 2013 EEIR revenue of $15.1 million and other regulatory disallowances of $1.1 million. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements;

• MidAmerican merger-related costs of $21.4 million as discussed in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements;

• An increase in other operating expense primarily due to an increase in regulatory expenses, a $3.4 million reduction in capitalized costs as a result of a decrease in construction activity, an increase in chemical and operating expenses at the Reid Gardner and Clark Generating Stations, an increase in outside consulting fees, and increased meter software maintenance and right of way. See the Utilities’ respective Results of Operations for further discussion;

• An increase in depreciation expense primarily due to the completion of various projects; and

• A decrease in other income primarily due to income recognized in 2012 for a construction contract settlement for the Harry Allen Generating Station and the gain on sale of telecommunications towers recorded in 2012.   

These increases were partially offset by the following pre-tax items:

• An increase in gross margin of $14.1 million not including the disallowance and provision discussed above. See the Utilities’ respective Results of Operations for further discussion of gross margin;

• A decrease in maintenance expense primarily due to a decrease in outages;

• A decrease in interest expense primarily due to the redemption of NPC’s 6.5% General and Refunding Mortgage Notes, Series I in April 2012; and

• A decrease in interest expense on regulatory items primarily due to lower over collected deferred energy and regulatory balances.

NVE Transformation

Beginning in 2006, NVE committed to an energy strategy to manage resources against our load by constructing/purchasing generating facilities, purchasing and developing renewable energy, encouraging energy efficiency and conservation programs, as well as expanding our transmission capability in an effort to reduce our reliance on purchased power.  The implementation of this strategy required significant amounts of liquidity and capital.  To meet these capital requirements during the transformation, NVE and the Utilities issued, refinanced and reduced debt which improved credit ratings and decreased interest costs.  At the same time, management worked with the PUCN to communicate the necessity of investments to better serve our customers, the prudency of costs incurred and the importance of a reasonable and timely return on such investments for our shareholders. 

The energy strategy and regulatory diligence discussed above created a strong foundation for NVE and the Utilities to earn their allowable return on their investments while meeting a higher percentage of their load through owned generation.  Additionally, as a result of their financial policies, which focused on lowering interest rates and reducing debt, interest costs and their capital structure continue to improve.  Furthermore, through employee dedication and increased use of technology we continue to improve processes to enhance performance while keeping operating and maintenance costs relatively stable.  As a result, NVE expects to generate free cash flow in 2013, which will continue to provide NVE the ability to maintain its dividend. 

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Key Initiatives

The economy in Nevada continues to recover slowly.  While a low growth environment can be challenging, the foundation established in prior years, including establishing energy independence, improving capital structure and liquidity and managing our regulatory environment, has positioned the Utilities to operate in this environment.  However, NVE and the Utilities continue to implement and develop key initiatives that collectively may further strengthen our capital structure and to consider new investment opportunities.  In addition, NVE management remains focused on the execution of the MidAmerican Merger. These initiatives should enable us to contain operating and maintenance costs while effectively managing our regulatory environment and continuing to promote and improve a safe and reliable work environment.  These key initiatives are discussed below.

  Continuous Improvement ofSafety 

The safety of NVE’s employees and the public is a core value of NVE and the Utilities. Accordingly, NVE has worked to integrate a set of safety principles into its business operations and culture.  These principles include not only complying with applicable safety, health and security regulations, but also implementing programs and processes aimed at continually improving safety and security conditions.  Our initiatives in 2013 and beyond will continue modeling a safety culture in all areas of the company. 

  Construction of ON Line

ON Line is Phase 1 of a joint project between the Utilities and GBT-South. Completion of ON Line, expected in December 2013, will connect NVE’s southern and northern service territories.  ON Line will provide:

• Ability to dispatch energy jointly throughout the state;

• Access for southern Nevada to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to meet its Portfolio Standard; and

• Ability to optimize its generating and transmission facilities to benefit its customers.

One Company Merger

In May 2013, NPC and SPPC filed a joint application with the PUCN to consolidate the Utilities into a single jurisdictional utility. The joint application with the PUCN requested the following:

• Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC’s assets and obligations to NPC, and renaming the surviving utility "NV Energy Operating Company" (NVEOC);

• Authority to transfer SPPC’s certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC’s CPCN to reflect the name of the surviving utility, NVEOC; and

• Authority to transfer all SPPC’s electric and gas utility assets, including electric generation assets, to NPC.

The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.”  The PUCN is not bound by any statutory deadlines with respect to this application. Hearings were expected to begin in February 2014, but the Utilities are seeking to delay the proceedings to the second half of 2014. 

In May 2013, NVE, NPC and SPPC filed an application with the FERC under Section 203 of the Federal Power Act for Approval of Internal Reorganization.  In their request, NPC and SPPC requested FERC authorization for an internal corporate reorganization under which SPPC will merge into NPC and be renamed NVEOC.  On October 21, 2013, NVE, NPC and SPPC submitted an informational filing with FERC indicating that given the status of an application pending before the PUCN, the applicants did not object to FERC deferring its consideration of the application. The application remains pending before FERC for consideration.  

  Empower Customers through Focused Service and Efficiency Programs

NV Energize is a NVE project that includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management.  The NV Energize capabilities will allow NVE to help customers better manage their usage with the most cost-effective mix of pricing, service, efficiency and conservation options.  Since April 30, 2013, the project was deemed to be substantially complete.  SPPC has included its proportionate share of costs, in its 2013 GRC, and NPC’s proportionate share of costs will be included in a future rate case. 

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The NV Energize system provides more convenience for customers and is achieving operating savings through both automated meter reading and the elimination annually of approximately 1 million trips to customers’ premises to process service requests.  The system also enables NVE to launch new customer programs.  Recruitment of participants for a trial of a combination of time based rates, supporting technology and education options is now underway.  New detailed customer usage reports have been integrated into our web self-service capability, and customers can also request alerts on their billing information.  An enhanced air conditioning demand response program was launched in the fourth quarter.   It is designed to provide energy market based rebates for specific event participation and also includes an energy efficiency management capability.  Similar programs for commercial customers are under development.

Managing Generation Portfolio within Environmental Compliance and NVision

As discussed further in Note 8, Commitments and Contingencies, of the Condensed Notes to Financial Statements, NVision is NVE’s comprehensive plan for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and other electric generating plants. In June 2013, the Nevada State Legislature passed SB 123, which was supported by NVE as part of its NVision initiative.  The Utilities expect to file an emissions reduction plan in 2014 to specifically address the plan details.

Also discussed in more detail in Note 8, Commitments and Contingencies, of the Condensed Notes to Financial Statements, certain generating stations of NVE are affected under EPA’s Regional Haze Rules and Mercury and Air Toxics Standards (MATS).  The implementation costs of these rules are significant.  Therefore, NVE must balance the costs of implementing the retrofit and control technology associated with the Regional Haze Rule and MATS standards with the effects of NVision, current and future load requirements, retirements of generating stations, plant outages and the ability to serve customers reliably.  To that end, the PUCN has accepted the Utilities’ resource plan to install necessary controls on the Tracy Generating Station Unit 3 and Fort Churchill Generating Station Units 1 and  2 to comply with Regional  Haze.  Tracy Generating Station Units 1 and 2 will be retired on or before the regional haze compliance date.  Reid Gardner Generating Station Units 1, 2 and 3 are also affected by the regional haze compliance date, but no decision has been made for these units at this time as NVE considers the impacts of NVision on these units. In addition, the Utilities anticipate that sulfur dioxide (SO2) and/or acid gas reduction will be required at SPPC’s Valmy Generating Station Unit 1 to achieve compliance with the MATS standards. Furthermore, NPC expects to file an emissions reduction plan in 2014 to specifically address its 11.3% ownership participation in the Navajo Generating Station, as a result of a number of uncertainties, as well as environmental compliance and the passage of NVision.

     Investment Opportunities

NVE continues to explore investment opportunities that may benefit our customers and that will add to our core business of generation, transmission and distribution of energy.  In addition, NVE’s geographical location affords it access to various renewable resources for potential investment opportunities.

NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. and Other Subsidiaries

NVE (Holding Company)

The operating results of NVE primarily reflect those of NPC and SPPC, discussed later.  The holding company’s (stand alone) operating results included approximately $18.7 million and $18.9 million of long-term debt interest costs for the nine months ended September 30, 2013 and 2012, respectively. 

For the nine month period ended September 30, 2013, NPC and SPPC paid $105.0 million and $40.0 million, respectively, in dividends to NVE.  On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively.

Other Subsidiaries

Subsidiaries of NVE, other than NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.

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ANALYSIS OF CASH FLOWS

Cash From Operating Activities

NVE’s net cash flows from operating activities were $553.7 million and $644.2 million for the nine months ended September 30, 2013 and 2012, respectively.

The decrease in cash from operating activities was primarily due to:

• Under-collection of energy costs due to higher energy costs of $306.4 million, offset by reduced refunds to customers of $121.7 million;

• Reduced EEPR collections of $50.1 million;

• Payments in 2013 for outages that occurred in 2012 at the Reid Gardner and Lenzie Generating Stations of $22.7 million; and

• Reduced revenues due to decreased BTER and EEPR rates combined with reduced customer energy usage due to cooler summer weather in 2013 compared to the same period in 2012.

The decrease in cash from operating activities was partially offset by:

• Reduced coal purchases of $34.5 million;

• Reduced spending on renewable programs of $27.8 million; and

• Receipt of approximately $9.0 million in insurance proceeds related to a previous claim.

Cash Used By Investing Activities

NVE’s net cash used by investing activities were $(233.3) million and $(325.2) million for the nine months ended September 30, 2013 and 2012, respectively.

The decrease in cash used by investing activities was primarily due to:

• Reduced capital expenditure for the NV Energize project of $95.5 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $28.0 million; and

• Reduced capital maintenance at Reid Gardner, Lenzie and Silverhawk Generating Stations of $54.2 million.

Cash Used By Financing Activities

NVE’s net cash flows used by financing activities were $(245.6) million and $(257.0) million for the nine months ended September 30, 2013 and 2012, respectively.

The decrease in cash used by financing activities was primarily due to:

• Issuance of SPPC’s $250 million, 3.375% General and Refunding Mortgage Notes, Series T debt; and

• Reduction in cash used by NPC to retire debt of $166.9 million.

The decrease in cash used by financing activities was partially offset by:

• Redemption of SPPC’s $250 million, 5.45% General and Refunding Mortgage Notes, Series Q debt;

• Reduction of draws from the NPC revolving credit facility of $135.0 million; and

• Increased dividends to shareholders of $23.3 million.

NVE paid common stock dividends of $134.3 million and $110.9 million during the nine months ended September 30, 2013 and 2012, respectively.

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

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over-collected BTER amounts from customers.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes and economic conditions. 

Available Liquidity as of September 30, 2013 (in millions)
	NVE		NPC		SPPC
Cash and Cash Equivalents	$	33.1	$	255.2	$	84.1
Balance available on Revolving Credit Facilities(1)	N/A		500.0		243.7
	$	33.1	$	755.2	$	327.8

⁽¹⁾  As of November 6, 2013, NPC and SPPC had approximately $500.0 million and $244.0 million available under their revolving credit facilities, which includes reductions in availability for letters of credit.

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.

For the remainder of 2013, NVE and the Utilities have no other debt maturities. NPC’s $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014. Additionally, in October of 2014, NVE's $195.0 million Term Loan will mature. To meet these long-term maturing debt obligations, the Utilities intend to use a combination of internally generated funds, the Utilities’ revolving credit facilities, and/or the issuance of long-term debt.  The Utilities’ credit ratings on their senior secured debt remains at investment grade (see Credit Ratings below).  NVE and the Utilities have not recently experienced any limitations in the credit markets, nor do we expect any for the remainder of 2013.  However, disruption in the banking and capital markets not specifically related to NVE and the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.    

In prior years, NVE and the Utilities required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As NVE and the Utilities have transitioned to slower growth, the amount of capital expenditures has declined.  NVE’s and the Utilities’ investment in generating stations in the past several years and more stable energy markets have positioned the Utilities to better manage and optimize their resources.  As a result, NVE and the Utilities anticipate that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of the Utilities’ revolving credit facilities.  Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, NVE and the Utilities expect to generate free cash flow in 2013; however, NVE’s and the Utilities’ cash flow may vary from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to maintain our dividend payout and for potential investment opportunities.    

However, if energy costs rise at a rapid rate, 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 under such circumstances, NVE and the Utilities may be required to delay capital expenditures or refinance debt.  Additionally, if deemed prudent, the Utilities may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs.  Currently, the Utilities are not operating under a PUCN approved hedging plan.  Hedging transactions may have a material impact on the Utilities’ cash flows, unless recovered in rates in a timely manner. 

As of November 6, 2013, NVE has approximately $10.8 million payable of debt service obligations remaining for 2013, which it intends to fund through dividends from subsidiaries.  See Factors Affecting Liquidity-Dividends from Subsidiaries, below.  For the nine months ended September 30, 2013, NPC and SPPC paid dividends to NVE of approximately $105.0 million and $40.0 million, respectively.  On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 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, environmental compliance, improvement and maintenance of facilities.  As discussed in Note 12, Commitments and Contingencies, of the 2012 Form 10-K, capital projects include NPC’s payment of Reid Gardner Generating Station Unit 4 from CDWR, which was completed in October 2013 for approximately $47.6 million. 

During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in NVE’s 2012 Form 10-K except that in June 2013, SPPC entered into a long-term capital lease for a solar array facility, still subject to commercial operation and approval by the PUCN.  The contract requires SPPC to make annual payments of approximately $3.0 million per year for a twenty year period.  However, SPPC has the option to terminate the lease and purchase the facility on or after the sixth anniversary of the commercial operation date of the facility for approximately $20.0 million. 

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Financing Transactions

Nevada Power Company

 In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A.  In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.  

Sierra Pacific Power Company

In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand, to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013. 

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 September 30, 2013, NVE (consolidated) would be allowed to incur up to $3.7billion 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 September 30, 2013, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: a $195 million Term Loan due October 2014; and $315 million of 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 September 30, 2013, NVE, NPC, SPPC and their subsidiaries had approximately $4.9 billion of debt and other obligations outstanding, consisting of approximately $3.2 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510.0 million of debt at the holding company and other subsidiaries.  Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

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.  While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of September 30, 2013, there were no dividend restrictions imposed on the Utilities by the PUCN.

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 being rated investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as such 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.

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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.  On May 22, 2013, Moody’s upgraded NVE’s, NPC’s and SPPC’s ratings.  On May 30, 2013, Fitch and Standard & Poor’s upgraded NPC’s and SPPC’s rating outlook from Stable to Positive.  NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P.  As of September 30, 2013, the ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
NVE	Sr. Unsecured Debt	BB+	Baa3*	BB+
NPC	Sr. Secured Debt	BBB+*	A3*	BBB+*
SPPC	Sr. Secured Debt	BBB+*	A3*	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 and S&P’s rating outlooks are Positive, while Moody’s rating outlook is Stable for NVE, NPC and SPPC.  

            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 September 30, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $49.7 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 not required to be marked-to-market on the balance sheet.

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 mean 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

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event of credit rating downgrades.   As of September 30, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million.  Of this amount, approximately $26.0 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 $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings both are downgraded to below investment grade.

Financial Gas Hedges

The Utilities may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K, 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.  Currently, there are no negative mark-to-market exposures that would impact borrowings of the Utilities.  If deemed prudent, the Utilities may 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.

Change of Control Provisions; Consent of Lenders

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination.  The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities.  As a result, NVE, NPC and SPPC will be required to offer to purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers.  The average interest rate under these financing agreements is approximately 6.25%, 6.42% and 5.51% for NVE, NPC and SPPC, respectively.  To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities’ revolving credit facilities or the issuance of long-term debt. Furthermore, NVE and the Utilities were required to obtain consents from lenders under the terms of Utilities’ revolving credit facilities and NVE’s Term Loan before consummating the MidAmerican Merger. In November 2013, NVE amended its Term Loan and NPC and SPPC amended their revolving credit facilities, in each case to permit the MidAmerican Merger.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of approximately $164.4 million during the three months ended September 30, 2013, compared to $195.2 million for the same period in 2012. During the nine months ended September 30, 2013, NPC recognized net income of approximately $228.6 million, compared to $256.2 million for the same period in 2012.

For the nine month period ended September 30, 2013, NPC paid $105.0 million in dividends to NVE.  On November 6, 2013, NPC declared a dividend of $73.0 million to NVE.

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

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NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which NPC calculates as operating revenues less energy costs, energy efficiency program costs and regulatory disallowances, provides a measure of income available to support the other operating expenses of NPC.  For reconciliation to operating income, see Note 3, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments and regulatory disallowances (which are required by statute to be filed every three years).

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

		Three Months Ended September 30,										Nine Months Ended September 30,
		2013			2012			Variance			% Change	2013			2012			Variance			% Change
Operating Revenues:		$	786,142		$	802,334		$	(16,192	)	(2.0)%	$	1,695,129		$	1,751,165		$	(56,036	)	(3.2)%
Energy Costs:
	Fuel for power generation	163,127			123,992			39,135			31.6%	412,904			285,799			127,105			44.5%
	Purchased power	172,582			171,687			895			0.5%	383,386			388,494			(5,108		)	(1.3)%
	Deferred energy	(45,381		)	(22,685		)	(22,696		)	100.0%	(154,484		)	(15,461		)	(139,023		)	899.2%
Energy efficiency program costs		13,998			28,492			(14,494		)	(50.9)%	32,807			65,466			(32,659		)	(49.9)%
Regulatory disallowance		11,866			—			11,866			N/A	11,866			—			11,866			N/A
	Total Costs	$	316,192		$	301,486		$	14,706		4.9%	$	686,479		$	724,298		$	(37,819	)	(5.2)%
Gross Margin		$	469,950		$	500,848		$	(30,898	)	(6.2)%	$	1,008,650		$	1,026,867		$	(18,217	)	(1.8)%

Gross margin decreased for the three and nine months ended September 30, 2013, compared to the same period in 2012. The decrease is primarily due to the disallowance of EEIR revenue and carrying charge and other deferred energy disallowances of $11.9 million (pre-tax) and a provision of $11.1 million (pre-tax) recorded against 2013 EEIR revenues, as a result of the precedent set by the PUCN’s ruling in NPC’s EEIR filing, as well as, NPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributing to the decrease in margin was a decrease in usage primarily due to a decrease in CDDs, as shown in the table below. The decrease was partially offset by customer growth and an increase in BTGR revenue.

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period.  A degree day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicate 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 HDDs and CDDs within NPC’s service territory:

		Three Months Ended September 30,						Nine Months Ended September 30,
		2013	2012	Variance		% Change		2013	2012	Variance		% Change
NPC
	Heating	—	—	—		N/A		1,084	986	98		9.9	%
	Cooling	2,164	2,313	(149	)	(6.4	)%	3,658	3,771	(113	)	(3.0	)%

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

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Operating Revenue
			Three Months Ended September 30,									Nine Months Ended September 30,
			2013		2012		Variance			% Change		2013		2012		Variance			% Change
Operating Revenues:
	Residential		$	420,072	$	436,534	$	(16,462	)	(3.8	)%	$	891,024	$	915,953	$	(24,929	)	(2.7	)%
	Commercial		120,407		121,334		(927		)	(0.8	)%	305,876		318,126		(12,250		)	(3.9	)%
	Industrial		226,739		227,824		(1,085		)	(0.5	)%	452,825		473,548		(20,723		)	(4.4	)%
		Retail revenues	767,218		785,692		(18,474		)	(2.4	)%	1,649,725		1,707,627		(57,902		)	(3.4	)%
	Other		18,924		16,642		2,282			13.7	%	45,404		43,538		1,866			4.3	%
		Total Operating Revenues	$	786,142	$	802,334	$	(16,192	)	(2.0	)%	$	1,695,129	$	1,751,165	$	(56,036	)	(3.2	)%
Retail sales in thousands of MWhs
	Residential		3,627		3,752		(125		)	(3.3	)%	7,592		7,619		(27		)	(0.4	)%
	Commercial		1,329		1,374		(45		)	(3.3	)%	3,423		3,480		(57		)	(1.6	)%
	Industrial		2,078		2,145		(67		)	(3.1	)%	5,756		5,836		(80		)	(1.4	)%
Retail sales in thousands of MWhs			7,034		7,271		(237		)	(3.3	)%	16,771		16,935		(164		)	(1.0	)%
Average retail revenue per MWh			$	109.07	$	108.06	$	1.01		0.9	%	$	98.37	$	100.83	$	(2.46	)	(2.4	)%

NPC’s retail revenues decreased for the three months ended September 30, 2013, as compared to the same period in 2012 due to $25.8 million in decreased usage primarily resulting from a decrease in CDDs, as shown in the table above, and an additional $14.4 million due to decreased EEPR rates, effective January 1, 2013. Also contributing to the decrease was a provision of $11.1 million recorded against 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in NPC’s EEIR filing and NPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013.   See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance.  These decreases were offset by an increase of $26.3 million as a result of NPC’s various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K) and $6.0 million due to retail customer growth.

For the three months ended September 30, 2013, the average number of retail customers increased by 1.3%, consisting of an increase in residential and commercial customers of 1.3% and 1.7%, respectively, and a decrease in industrial customers of 0.6%, compared to the same period in the prior year.

Electric Operating Revenues - Other increased for the three months ended September 30, 2013, compared to the same period in 2012, due to an increase in transmission rates of $2.4 million as a result of the FERC rate case effective June 1, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion.

NPC’s retail revenues decreased for the nine months ended September 30, 2013, as compared to the same period in 2012 due to $32.4 million from decreased EEPR rates effective January 1, 2013, $19.4 million due to a decrease in CDDs, as shown in the table above, $11.1 million provision for EEIR revenue recorded in 2013, as discussed above, and $8.6 million as a result of NPC’s various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K). These decreases were offset by an increase of $9.2 million from residential customer growth.

For the nine months ended September 30, 2013, the average number of retail customers increased by 1.0%, consisting of an increase in residential and commercial customers of 1.0% and 1.6%, respectively, and a decrease in industrial customers of 0.1%, compared to the same period in the prior year.

Electric Operating Revenues - Other increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to an increase in transmission rates of $2.1 million as a result of the FERC rate case effective June 1, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion.

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

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• resource constraints

• transmission constraints

• natural gas constraints

• long-term contracts

• mandated power purchases; and

• volatility of commodity prices

		Three Months Ended September 30,									Nine Months Ended September 30,
		2013		2012		Variance			% Change		2013		2012		Variance			% Change
Energy Costs
	Fuel for power generation	$	163,127	$	123,992	$	39,135		31.6	%	$	412,904	$	285,799	$	127,105		44.5	%
	Purchased power	172,582		171,687		895			0.5	%	383,386		388,494		(5,108		)	(1.3	)%
Energy Costs		$	335,709	$	295,679	$	40,030		13.5	%	$	796,290	$	674,293	$	121,997		18.1	%
MWhs
	MWhs Generated (in thousands)	5,242		5,105		137			2.7	%	13,310		12,264		1,046			8.5	%
	Purchased Power (in thousands)	2,077		2,392		(315		)	(13.2	)%	4,225		5,415		(1,190		)	(22.0	)%
Total MWhs		7,319		7,497		(178		)	(2.4	)%	17,535		17,679		(144		)	(0.8	)%
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	31.12	$	24.29	$	6.83		28.1	%	$	31.02	$	23.30	$	7.72		33.1	%
	Average cost per MWh of Purchased Power	$	83.09	$	71.78	$	11.32		15.8	%	$	90.74	$	71.74	$	19.00		26.5	%
	Average total cost per MWh	$	45.87	$	39.44	$	6.43		16.3	%	$	45.41	$	38.14	$	7.27		19.1	%

Energy Costs and the average total cost per MWh increased for the three and nine months ended September 30, 2013, compared to the same period in 2012, primarily due to an increase in costs associated with higher natural gas prices partially offset by a decrease in the volume of purchased power which is typically more expensive than generated power. Overall volume decreased slightly primarily due to a decrease in CDDs, as shown in the table above.

• Fuel for generation costs increased for the three months ended September 30, 2013, compared to the same period in 2012.  Contributing to the increase was approximately $34.1 million due to higher natural gas prices, partially offset by a decrease in the volume of natural gas of $8.4 million. The increase in the volume of coal and the price of coal prices also contributed approximately $12.2 million and $1.2 million, respectively, to the increase in fuel for generation costs.

Fuel for generation costs increased for the nine months ended September 30, 2013, compared to the same periods in 2012.  Contributing to the increase was approximately $96.4 million and $8.2 million due to higher natural gas prices and the volume of natural gas used, respectively. The increase in the volume of coal used and a slight increase in coal prices also contributed approximately $21.6 million and $0.9 million, to the increase in fuel for generation costs.

• Purchased power costs increased for the three months ended September 30, 2013, compared to the same period in 2012.  The increase in purchased power costs for the three month period was primarily due to a $23.6 million and a $3.7 million increase in the price of non-renewable purchases and renewable purchases, respectively. The increase in cost was largely offset by a decrease in the volume of non-renewable power purchases and renewable power purchases of approximately $16.4 million and $10.0 million, respectively.

Purchased power costs decreased for the nine months ended September 30, 2013, compared to the same period in 2012. The decrease is primarily due to $72.2 million and $35.6 million attributable to decreased volume of non-renewable power purchases and renewable purchases, respectively. The decrease was largely offset by an increase in the price of non-renewable purchases of approximately $70.8 million, primarily due to higher natural gas prices, and an increase in the price of renewable purchases of $31.9 million.

Deferred Energy
	Three Months Ended September 30,										Nine Months Ended September 30,
	2013			2012			Variance			% Change	2013			2012			Variance			% Change
Deferred energy	$	(45,381	)	$	(22,685	)	$	(22,696	)	100.0%	$	(154,484	)	$	(15,461	)	$	(139,023	)	899.2%

Deferred Energy for the three months ended September 30, 2013 and 2012 include amortization of deferred energy of $(6.2) million and $(58.3) million, respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further

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contributing to the deferred energy balance are under-collections of amounts recoverable in rates of $(39.2) million in 2013 and over-collections of $35.6 million in 2012. 

Amounts for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(57.1) million and $(136.5) million, respectively which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy balance are under-collections of amounts recoverable in rates of $(97.4) million in 2013, and over-collections of $121.0 million in 2012. 

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.  Reference Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Other Operating Expenses
	Three Months Ended September 30,								Nine Months Ended September 30,
	2013		2012		Variance			% Change	2013		2012		Variance			% Change
Energy efficiency program costs	$	13,998	$	28,492	$	(14,494	)	(50.9)%	$	32,807	$	65,466	$	(32,659	)	(49.9)%
Regulatory disallowance	$	11,866	$	—	$	11,866		N/A	$	11,866	$	—	$	11,866		N/A
Merger-related costs	$	5,620	$	—	$	5,620		N/A	$	14,487	$	—	$	14,487		N/A
Other operating expenses	$	70,844	$	65,372	$	5,472		8.4%	$	208,336	$	200,484	$	7,852		3.9%
Maintenance	$	11,208	$	12,533	$	(1,325	)	(10.6)%	$	45,172	$	52,594	$	(7,422	)	(14.1)%
Depreciation and amortization	$	68,849	$	66,975	$	1,874		2.8%	$	207,915	$	201,096	$	6,819		3.4%

For the three and nine months ended September 30, 2013 energy efficiency program costs decreased compared to the same periods in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013. Reference Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortizations rate filings. See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further information on EEPR rates effective October 2013.

The regulatory disallowance consists of $10.8 million related to EEIR revenues earned in 2012 (including carrying charges) in excess of NPC’s authorized ROR.  The amount also includes a disallowance of approximately $1.1 million in deferred energy.  See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements. 

As discussed further in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements, in May 2013, NVE and the Utilities entered into the MidAmerican Merger Agreement.  As a result of the MidAmerican Merger, NPC incurred $5.6 million and $14.5 million in merger-related fees and stock compensation costs for the three and nine months ended September 30, 2013, respectively.  Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation upon announcement of the MidAmerican Merger.  NPC expects to incur additional merger-related fees upon consummation of the MidAmerican Merger.

Other operating expense increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $2.2 million in increased meter software maintenance and right of way leases, $1.2 million increase in overall generation operating expenses, $1.0 million increase due to IBEW 396 collective bargaining agreement ratification bonus and wage increase, and $0.4 million increase in regulatory expenses.

Other operating expense increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $2.5 million reduction in capitalized costs as a result of a decrease in construction activity, a $2.5 million increase in chemical and operating expenses at the Reid Gardner and Clark Generating Stations, a $2.3 million increase in outside consulting fees, $1.7 million increase in regulatory expenses and $1.6 million in increased meter software maintenance and right of way leases.

Maintenance expense decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $1.2 million of major planned maintenance outages in 2012 at the Silverhawk and Harry Allen Generating Stations and lower expenses at Higgins Generating Station.

Maintenance expense decreased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to $10.0 million of major maintenance outages in 2012 at the Silverhawk, Lenzie, Harry Allen and Reid Gardner Generating Stations, offset by $2.8 million of planned maintenance outages in 2013 at the Higgins and Clark Generating Stations.

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Depreciation and amortization increased for the three and nine months ended September 30, 2013 compared to the same period in 2012, primarily due to general increases in plant-in-service.

Interest Expense
	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Variance		% Change	2013		2012		Variance		% Change
Interest expense
(net of AFUDC-debt: $1,520, $1,528, $4,763 and $4,021)	$	52,856	$	51,784	$	1,072	2.1%	$	155,758	$	158,791	(3,033	)	(1.9)%

Interest expense increased for the three months ended September 30, 2013, compared to the same period in 2012 due to interest charges of $1.7 million for an assessment on a right of way lease, offset by a $0.3 million decrease in debt amortization expense and a $0.3 million decrease in interest for debt. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 5, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.

Interest expense decreased for the nine months ended September 30, 2013, compared to the same period in 2012 due to a $2.5 million decrease in interest costs primarily due to the redemption of the 6.5% General and Refunding Mortgage Notes, Series I in April 2012, an increase in AFUDC-debt of $0.7 million,a $0.7 million decrease in interest for debt, and a $0.6 million decrease in debt amortization expense. Offsetting these decreases was interest charges of $1.7 million for an assessment on a right of way lease. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 5, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.

Other Income (Expense)
	Three Months Ended September 30,											Nine Months Ended September 30,
	2013			2012			Variance			% Change		2013			2012			Variance			% Change
Interest income (expense) on regulatory items	$	(194	)	$	(1,623	)	$	1,429		(88.0	)%	$	(1,177	)	$	(5,488	)	$	4,311		(78.6	)%
AFUDC-equity	$	1,959		$	1,833		$	126		6.9	%	$	6,151		$	4,823		$	1,328		27.5	%
Other income	$	1,948		$	7,096		$	(5,148	)	(72.5	)%	$	5,330		$	14,197		$	(8,867	)	(62.5	)%
Other expense	$	(1,966	)	$	(2,823	)	$	857		(30.4	)%	$	(6,200	)	$	(7,162	)	$	962		(13.4	)%

Interest income (expense) on regulatory items decreased for the three and nine months ended September 30, 2013, compared to the same periods in 2012. The decrease was primarily due to a decrease in interest on deferred energy of $2.9 million and $7.1 million for the three and nine month periods, respectively, as a result of lower over-collected balances in 2013. The decrease in interest income (expense) on regulatory items was partially offset by $1.0 million and $3.6 million for the three and nine month periods, respectively, as a result of decreased interest income due to lower regulatory asset balances.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K. 

AFUDC-equity increased for the three and nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to various construction projects. 

Other income decreased for the three months ended September 30, 2013, compared to the same periods in 2012, due to a $5.5 million gain on the sale of telecommunication towers in 2012, offset slightly by higher gains on investments in 2013.

Other income decreased for the nine months ended September 30, 2013, compared to the same periods in 2012, due to a $5.5 million gain on the sale of telecommunication towers in 2012, a $4.9 million Harry Allen Generating Station construction project settlement recorded in 2012, offset slightly by several items, none of which were individually material.

Other expense decreased for the three and nine months ended September 30, 2013 compared to the same period in 2012, by several items, none of which were individually material.

ANALYSIS OF CASH FLOWS

Cash From Operating Activities

NPC’s net cash flows from operating activities were $399.2 million and $514 million for the nine months ended September 30, 2013 and 2012, respectively.

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The decrease in cash from operating activities was primarily due to:

• Under-collection of energy costs due to higher energy costs of $214 million, offset by reduced refunds to customers of $79.7 million;

• Reduced EEPR collections of $44.3 million;

• Payments in 2013 for outages that occurred in 2012 at Reid Gardner and Lenzie Generating Stations of $22.7 million;

• Timing of payments for energy costs of $4.9 million; and

• Reduced revenues due to decreased BTER and EEPR rates combined with reduced customer energy usage due to cooler summer weather in 2013 compared to the same period in 2012.

The decrease in cash from operating activities was partially offset by:

• Reduced coal purchases of $11.1 million; and

• Reduced spend on renewable programs of $7.4 million.

Cash Used By Investing Activities

NPC’s net cash used by investing activities were $(136.2) million and $(197.4) million for the nine months ended September 30, 2013 and 2012, respectively.

The decrease in cash used by investing activities was primarily due to:

• Reduced capital maintenance at Reid Gardner, Lenzie and Silverhawk Generating Stations of $54.2 million.

The decrease in cash used by investing activities was partially offset by:

• Reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $10.6 million.

Cash Used By Financing Activities

NPC’s net cash flows used by financing activities were $(209) million and $(258) million for the nine months ended September 30, 2013 and 2012, respectively.

The decrease in cash used by financing activities was primarily due to:

• A reduction in cash used to retire debt of $166.9 million; and

• Decreased dividends to NVE of $14 million.

The decrease in cash used by financing activities was partially offset by:

• Reduced draws from the NPC revolving credit facility of $135 million.

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.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions. 

Available Liquidity as of September 30, 2013 (in millions)
	NPC
Cash and Cash Equivalents	$	255.2
Balance available on Revolving Credit Facility(1)	500.0
	$	755.2

⁽¹⁾ As of November 6, 2013, NPC had approximately $500 million available under its revolving credit facility.

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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 has no further debt maturities for the remainder of 2013; however, NPC’s $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014.  To meet these maturing debt obligations, NPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt.  As of November 6, 2013, NPC has no borrowings on its revolving credit facility.  NPC’s credit ratings on its senior secured debt remains at investment grade (see Credit Ratings below).   NPC has not recently experienced any limitations in the credit markets, nor does NPC expect any significant limitations for the remainder of 2013.  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 prior years, NPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As NPC has transitioned to slower growth, the amount of capital expenditures required has declined.  NPC’s investment in generating stations in the past several years and more stable energy markets have positioned NPC to better manage and optimize its resources.  As a result, NPC anticipates that it will be able to meet short-term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility.  Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL and a decrease in capital expenditures, NPC expects to generate free cash flow in 2013; however, NPC’s cash flow may vary significantly from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.    

However, if energy costs rise at a rapid rate 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 under such circumstances, NPC may be required to delay capital expenditures, re-finance debt or receive capital contributions from NVE.

During the nine months ended September 30, 2013, NPC paid dividends to NVE of $105.0 million. On November 6, 2013, NPC declared a dividend to NVE of $73 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, environmental compliance, improvement and maintenance of facilities.  As discussed, in Note 12, Commitments and Contingencies, of the 2012 Form 10-K, capital projects include NPC’s payment of Reid Gardner Generating Station Unit 4 from CDWR, which was completed in October 2013 for approximately $47.6 million. 

During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in NPC’s 2012 Form 10-K.   

Financing Transactions

 In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A.  In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.  

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, its revolving credit facility agreement, and the terms of certain NVE debt.  As of September 30, 2013, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $725.0 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 September 30, 2013, 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 $725.0 million; (2) to refinance up to approximately $422.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion.  In May 2013, NPC and SPPC filed a joint financing application with the PUCN, see Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details;

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b. Financial covenants within NPC’s financing agreements - Under the NPC Credit Agreement, 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 1.00.  Based on financial statements for the period ended September 30, 2013, NPC was in compliance with this covenant and could incur up to $3.2billion of additional indebtedness

All other financial covenants contained in NPC’s financing agreements are suspended as NPC’s senior secured debt is currently 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 $3.7billion. 

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 and NVE’s 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 the NPC Indenture.

The NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada.  As of September 30, 2013, $3.7 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.8 billionof General and Refunding Mortgage Securities as of September 30, 2013.  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.  Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.

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

Credit Ratings

The liquidity of NPC, the cost and availability of borrowing by NPC under the NPC Credit Agreement, 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.  On May 22, 2013, Moody’s upgraded NPC’s ratings.  On May 30, 2013, Fitch and S&P upgraded NPC’s rating outlook from Stable to Positive.  NPC’s senior secured debt is rated investment grade by three NRSRO’s:  Fitch, Moody’s and S&P.  The senior secured debt credit ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
NPC	Sr. Secured Debt	BBB+*	A3*	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 and S&P’s rating outlooks are Positive, while Moody’s rating outlook is Stable for NPC.    

                        A security rating is not a recommendation to buy, sell or hold securities.  Security ratings are subject to revision and withdrawal at any time by the assigning rating organization.  Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

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Energy Supplier Matters

With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP.  The WSPP agreement 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 September 30, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $49.7 million payment or obligation to NPC.  These contracts qualify for the normal purchases and normal sales 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.

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 September 30, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million.  Of this amount, approximately $26 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 $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both 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 in Note 6, Long Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K,  NPC’s Financing Transactions, the availability under the NPC’s revolving credit facility 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 facility shall at no time exceed 50% of the total commitments then in effect under the credit facility.  Currently, there are no negative mark-to-market exposures that would impact borrowings of NPC.  If deemed prudent, NPC may 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 their respective 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.

Change of Control Provisions; Consent of Lenders

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of

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control payments in the event of an occurrence of a qualified termination.  The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NPC.  As a result, NPC will be required to offer to purchase approximately $3.1 billion of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, NPC is unable to determine the extent to which holders of these debt securities will accept such tender offers.  The average interest rate under NPC’s debt securities is approximately 6.42%.  To the extent that debt securities are tendered pursuant to the required tender offers, NPC intends to fund the purchases using a combination of internal funds, its revolving credit facility or the issuance of long-term debt. Furthermore, NPC was required to obtain consents from lenders under the terms of its revolving credit facility before consummating the MidAmerican Merger. In November 2013, NPC amended its revolving credit facility to permit the MidAmerican Merger.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $29.3 million for the three months ended September 30, 2013, compared to net income of $34.4 million for the same period in 2012.  During the nine months ended September 30, 2013, SPPC recognized net income of approximately $61.9 million compared to $65.8 million for the same period in 2012.

During the nine months ended September 30, 2013, SPPC paid dividends to NVE of $40.0 million.   On November 6, 2013, SPPC declared a dividend of $37.0 million to NVE.

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

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which SPPC calculates as operating revenues less energy costs, energy efficiency program costs and regulatory disallowances, provides a measure of income available to support the other operating expenses of SPPC.  For reconciliation to operating income, see Note 3, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

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

		Three Months Ended September 30,											Nine Months Ended September 30,
		2013			2012			Variance			% Change		2013			2012			Variance			% Change
Operating Revenues:
	Electric	$	213,463		$	212,073		$	1,390		0.7	%	$	560,392		$	549,886		$	10,506		1.9	%
	Gas	13,543			12,077			1,466			12.1	%	73,480			77,543			(4,063		)	(5.2	)%
		$	227,006		$	224,150		$	2,856		1.3	%	$	633,872		$	627,429		$	6,443		1.0	%
Energy Costs:
	Fuel for power generation	54,827			47,324			7,503			15.9	%	141,277			115,137			26,140			22.7	%
	Purchased power	33,388			33,999			(611		)	(1.8	)%	114,755			98,400			16,355			16.6	%
	Gas purchased for resale	7,383			5,382			2,001			37.2	%	62,277			46,491			15,786			34.0	%
	Deferred energy - electric - net	(7,925		)	(5,498		)	(2,427		)	44.1	%	(44,223		)	(13,854		)	(30,369		)	219.2	%
	Deferred energy - gas - net	(1,964		)	(853		)	(1,111		)	130.2	%	(22,315		)	(970		)	(21,345		)	2,201	%
Energy efficiency program costs		2,044			4,092			(2,048		)	(50.0	)%	5,679			11,143			(5,464		)	(49.0	)%
Regulatory disallowance		5,469			—			5,469			N/A		5,469			—			5,469			N/A
	Total Costs	$	93,222		$	84,446		$	8,776		10.4	%	$	262,919		$	256,347		$	6,572		2.6	%
	Cost by Segment:
	Electric	$	87,803		$	79,917		$	7,886		9.9	%	$	222,957		$	210,826		$	12,131		5.8	%
	Gas	5,419			4,529			890			19.7	%	39,962			45,521			(5,559		)	(12.2	)%
		$	93,222		$	84,446		$	8,776		10.4	%	$	262,919		$	256,347		$	6,572		2.6	%
	Gross Margin by Segment:
	Electric	$	125,660		$	132,156		$	(6,496	)	(4.9	)%	$	337,435		$	339,060		$	(1,625	)	(0.5	)%
	Gas	8,124			7,548			576			7.6	%	33,518			32,022			1,496			4.7	%
	Gross Margin	$	133,784		$	139,704		$	(5,920	)	(4.2	)%	$	370,953		$	371,082		$	(129	)	—	%

Electric gross margin decreased for the nine months ended September 30, 2013 compared to the same period in 2012.  The decrease is primarily due to the disallowance of EEIR revenue and carrying charge of $5.5 million (pre-tax) and a provision of $4.0 million (pre-tax) recorded against 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in NPC’s EEIR filing, as well as, SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributing to the increase was customer growth and usage. The decrease was largely offset by an increase in customer usage, customer growth and an increase in sales of $3.8 million to Cal Peco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K).

Gas gross margin for the three and nine months ended September 30, 2013, compared to the same periods in 2012 increased slightly primarily due to weather.

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period.  A degree day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicate 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 HDDs and CDDs within SPPC’s service territory:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013	2012	Variance		% Change		2013	2012	Variance		% Change
SPPC
Heating	85	1	84		N/A		2,859	2,677	182		6.8	%
Cooling	914	1,020	(106	)	(10.4	)%	1,177	1,255	(78	)	(6.2	)%

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

Electric Operating Revenue
			Three Months Ended September 30,									Nine Months Ended September 30,
Operating Revenues:			2013		2012		Variance			% Change		2013		2012		Variance			% Change
	Residential		$	68,808	$	68,677	$	131		0.2	%	$	184,309	$	180,953	$	3,356		1.9	%
	Commercial		78,080		78,409		(329		)	(0.4	)%	201,761		200,912		849			0.4	%
	Industrial		48,722		48,541		181			0.4	%	122,082		120,234		1,848			1.5	%
		Retail  Revenues	195,610		195,627		(17		)	—	%	508,152		502,099		6,053			1.2	%
	Other		17,853		16,446		1,407			8.6	%	52,240		47,787		4,453			9.3	%
		Total Operating Revenues	$	213,463	$	212,073	$	1,390		0.7	%	$	560,392	$	549,886	$	10,506		1.9	%
Retail sales in thousands of MWhs
	Residential		671		667		4			0.6	%	1,794		1,737		57			3.3	%
	Commercial		851		849		2			0.2	%	2,268		2,233		35			1.6	%
	Industrial		701		686		15			2.2	%	2,092		2,005		87			4.3	%
Retail sales in thousands of MWhs			2,223		2,202		21			1.0	%	6,154		5,975		179			3.0	%
Average retail revenue per MWh			$	87.99	$	88.84	$	(0.85	)	(1.0	)%	$	82.57	$	84.03	$	(1.46	)	(1.7	)%

Retail revenue decreased for the three months ended September 30, 2013, as compared to the same period in 2012, primarily due to a provision of $4.0 million recorded against 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in SPPC’s EEIR filing and SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013.   See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributing to the decrease was $2.0 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013. These decreases were largely offset by $5.2 million of rate increases as a result of various BTER and DEAA quarterly and a $1.1 million increase from customer growth. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K.

For the three months ended September 30, 2013, the average number of residential and commercial customers increased 0.7% and 2.5%, respectively, while industrial customers remained the same compared to the same period in 2012.

Electric operating revenues - Other increased for the three months ended September 30, 2013, compared to the same periods in 2012, primarily due to an increase in energy sales of $1.5 million to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K).

Retail revenue increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to a $7.6 million increase in customer usage primarily due to an unusually cold January and unusually hot June and July, $4.8 million in rate increases due to various BTER and DEAA quarterly updates (see Note 4, Regulatory Actions of the Notes to Financial Statements) and a $1.8 million increase from customer growth. These increases were partially offset by $5.4 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013 and a provision of $4.0 million for 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in SPPC’s EEIR filing and SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013.  See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements).

For the nine months ended September 30, 2013, the average number of residential, commercial, and industrial customers increased 0.7%, 2.1%, and 1.8%, respectively, compared to the same period in 2012.

Electric operating revenues - Other increased for the nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to a $3.8 million increase in energy sales to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K) and $0.7 million increase in miscellaneous revenues.

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Gas Operating Revenue
		Three Months Ended September 30,									Nine Months Ended September 30,
		2013		2012		Variance			% Change		2013		2012		Variance			% Change
Gas Operating Revenues:
	Residential	$	7,750	$	7,306	$	444		6.1	%	$	39,781	$	45,104	$	(5,323	)	(11.8	)%
	Commercial	2,680		2,583		97			3.8	%	14,657		17,961		(3,304		)	(18.4	)%
	Industrial	1,041		906		135			14.9	%	4,591		5,115		(524		)	(10.2	)%
	Retail  Revenues	11,471		10,795		676			6.3	%	59,029		68,180		(9,151		)	(13.4	)%
	Wholesale Revenues	1,359		563		796			141.4	%	12,149		7,033		5,116			72.7	%
	Miscellaneous	713		719		(6		)	(0.8	)%	2,302		2,330		(28		)	(1.2	)%
	Total Gas Revenues	$	13,543	$	12,077	$	1,466		12.1	%	$	73,480	$	77,543	$	(4,063	)	(5.2	)%
Retail sales in thousands of Dths
	Residential	698		642		56			8.7	%	6,039		5,613		426			7.6	%
	Commercial	400		374		26			7.0	%	3,086		2,939		147			5.0	%
	Industrial	190		153		37			24.2	%	986		876		110			12.6	%
Retail sales in thousands of Dths		1,288		1,169		119			10.2	%	10,111		9,428		683			7.2	%
Average retail revenue per Dth		$	8.91	$	9.23	$	(0.32	)	(3.5	)%	$	5.84	$	7.23	$	(1.39	)	(19.2	)%

SPPC’s retail gas revenues increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to a $565 thousand increase in usage, due to an increase in HDDs as shown in the table above.

SPPC’s retail gas revenues decreased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $12.4 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012, and various BTER and DEAA quarterly updates (see Note 4, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K). The decrease was partially offset by a $2.8 million increase in customer usage, due to an increase in HDDs as shown in the table above.

Wholesale revenues increased for the three and nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to an increase in natural gas prices.

Energy Costs

Energy Costs include purchased power and fuel for generation. 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 purchased power versus fuel for generation can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:

• weather

• plant outages

• total system demand

• resource constraints

• transmission constraints

• gas transportation constraints

• natural gas constraints

• long-term contracts

• mandated power purchases

• generation efficiency; and

• volatility of commodity prices

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		Three Months Ended September 30,									Nine Months Ended September 30,
		2013		2012		Variance			% Change		2013		2012		Variance		% Change
Energy Costs:
	Fuel for power generation	$	54,828	$	47,324	$	7,504		15.9	%	$	141,277	$	115,137	$	26,140	22.7	%
	Purchased power	33,388		33,999		(611		)	(1.8	)%	114,755		98,400		16,355		16.6	%
Total Energy Costs		$	88,216	$	81,323	$	6,893		8.5	%	$	256,032	$	213,537	$	42,495	19.9	%
MWhs
	MWhs Generated (in thousands)	1,580		1,512		68			4.5	%	3,829		3,829		—		—	%
	Purchased Power (in thousands)	916		971		(55		)	(5.7	)%	3,169		3,031		138		4.6	%
Total MWhs		2,496		2,483		13			0.5	%	6,998		6,860		138		2.0	%
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	34.70	$	31.30	$	3.40		10.9	%	$	36.90	$	30.07	$	6.83	22.7	%
	Average cost per MWh of Purchased Power	$	36.45	$	35.01	$	1.44		4.1	%	$	36.21	$	32.46	$	3.75	11.5	%
	Average total cost per MWh	$	35.34	$	32.75	$	2.59		7.9	%	$	36.59	$	31.13	$	5.46	17.5	%

Energy costs and average cost per MWh increased for the three and nine months ended September 30, 2013, compared to the same period in 2012 primarily due to higher natural gas prices.

• Fuel for generation costs increased for the three months ended September 30, 2013, compared to the same period in 2012. Contributing to the increase was $5.2 million due to higher natural gas and coal prices. Also contributing to the increase was $1.2 million and $1.1 million in volume increases of coal and natural gas used for generation, respectively.

Fuel for generation costs increased for the nine months ended September 30, 2013 compared to the same period in 2012. Contributing to the increase was $26.8 million in higher natural gas prices. Higher costs were partially offset by a decrease in natural gas volume of approximately $13.0 million and an increase of $12.0 million in coal volume, respectively.

• Purchased power costs decreased for the three months ended September 30, 2013 compared to the same period in 2012. Approximately $1.8 million of the decrease is primarily due to decreased volume. The decrease was partially offset by an increase in the price of purchased power of $1.2 million.

Purchased power costs increased for the nine months ended September 30, 2013 compared to the same period in 2012. Contributing to the increase was an increase in price of $10.9 million and $1.5 million for non-renewable and renewable energy, respectively. Approximately $4.0 million of the increase was due to an increase in volume of power purchased.

Gas Purchased for Resale
	Three Months Ended September 30,								Nine Months Ended September 30,
	2013		2012		Variance		% Change		2013		2012		Variance		% Change
Gas purchased for resale	$	7,383	$	5,382	$	2,001	37.2	%	$	62,277	$	46,491	$	15,786	34.0	%
Gas purchased for resale (in thousands of Dths)	1,688		1,349		339		25.1	%	13,614		12,636		978		7.7	%
Average cost per Dth	$	4.37	$	3.99	$	0.38	9.5	%	$	4.57	$	3.68	$	0.89	24.2	%

Gas purchased for resale increased for the three months ended September 30, 2013, compared to the same period in 2012. Approximately $1.5 million of the increase is due to an increase in volume and approximately $0.5 million is due to higher natural gas prices. Volume increased primarily due to an increase in HDDs as shown in the table above.

Gas purchased for resale increased for the nine months ended September 30, 2013, compared to the same period in 2012. Approximately $11.3 million of the increase is due higher natural gas prices and approximately $4.5 million is due to an increase in volume. Volume increased primarily due to an increase in HDDs as shown in the table above.

Deferred Energy
	Three Months Ended September 30,										Nine Months Ended September 30,
	2013			2012			Variance			% Change	2013			2012			Variance			% Change
Deferred energy - electric - net	$	(7,925	)	$	(5,498	)	$	(2,427	)	44.1%	$	(44,223	)	$	(13,854	)	$	(30,369	)	219.2%
Deferred energy - gas - net	$	(1,964	)	$	(853	)	$	(1,111	)	130.2%	$	(22,315	)	$	(970	)	$	(21,345	)	2,200.5%
	$	(9,889	)	$	(6,351	)	$	(3,538	)	55.7%	$	(66,538	)	$	(14,824	)	$	(51,714	)	348.9%

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Deferred energy - electric for the three months ended September 30, 2013 and 2012 include amortization of deferred energy of $(4.5) million and $(19.3) million, respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy - electric balance are under-collections of amounts recoverable in rates of $(3.4) million in 2013 and over-collections of $13.8 million in 2012. 

Deferred energy - electric for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(23.7) million and $(65.0) million, respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy - electric balance are under-collections of amounts recoverable in rates of $(20.5) million in 2013 and over-collections of $51.2 million in 2012.

Deferred energy - gas for the three months ended September 30, 2013 and 2012 include amortization of deferred energy of $(1.9) million and $(2.2) million, respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy - gas balance for 2012 were over-collections recoverable in rates of $1.3 million. Under collections for the three months ended September 30, 2013 are immaterial. 

Deferred energy - gas for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(19.0) million and $(19.9) million, respectively, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the deferred energy - gas balance are under-collections of amounts recoverable in rates of $(3.3) million in 2013 and over-collections of $18.9 million in 2012.

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.  Reference Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Other Operating Expenses
	Three Months Ended September 30,								Nine Months Ended September 30,
	2013		2012		Variance			% Change	2013		2012		Variance			% Change
Energy efficiency program costs	$	2,044	$	4,092	$	(2,048	)	(50.0)%	$	5,679	$	11,143	$	(5,464	)	(49.0)%
Regulatory disallowance	$	5,469	$	—	$	5,469		N/A	$	5,469	$	—	$	5,469		N/A
Merger-related costs	$	2,008	$	—	$	2,008		N/A	$	5,528	$	—	$	5,528		N/A
Other operating expenses	$	34,394	$	34,128	$	266		0.8%	$	106,455	$	104,214	$	2,241		2.2%
Maintenance	$	5,968	$	6,481	$	(513	)	(7.9)%	$	20,956	$	23,596	$	(2,640	)	(11.2)%
Depreciation and amortization	$	27,952	$	27,537	$	415		1.5%	$	83,772	$	80,594	$	3,178		3.9%

For the three and nine months ended September 30, 2013, energy efficiency program costs decreased compared to the same periods in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013. Reference Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortizations rate filings. See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further information on EEPR rates effective October 2013.

The regulatory disallowance consists of $5.5 million related to EEIR revenues earned in 2012 (including carrying charges) in excess of SPPC’s authorized ROR.   See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements. 

As discussed further in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements, in May 2013, NVE and the Utilities entered into the MidAmerican Merger Agreement.  As a result of the MidAmerican Merger, SPPC incurred $2.0 million and $5.5 million in merger-related fees and stock compensation costs for the three and nine months ended September 30, 2013, respectively.  Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation upon announcement of the MidAmerican Merger.  SPPC expects to incur additional merger-related fees upon consummation of the MidAmerican Merger.

Other operating expense increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $0.7 million increase in regulatory expenses. The increase was offset by a $0.7 million decrease due to a 2012 claim settlement.

Other operating expense increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to $2.6 million increase in regulatory expenses, $0.9 million reduction in capitalized costs as a result of a decrease in construction activity. The increase was partially offset by a $0.9 million decrease in pension and benefit costs.

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Maintenance expense decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $0.2 million of 2012 major outage at the Tracy Generating Station and $0.2 million in 2012 maintenance at the Ft. Churchill Generating Station.

Maintenance expense decreased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to $3.7 million of planned major outages in 2012 at the Tracy, Valmy and Ft. Churchill Generating Stations, and $0.3 million of 2012 transmission poles maintenance expenses, offset by $1.5 million of 2013 turbine maintenance at the Tracy Generating Station.

Depreciation and amortization increased for the three and nine months ended September 30, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service.

Interest Expense
	Three Months Ended September 30,						Nine Months Ended September 30,
	2013		2012		Variance	% Change	2013		2012		Variance	% Change
Interest expense
(net of AFUDC-debt: $437, $448, $1,007 and $1,458)	(15,122	)	(15,298	)	176	(1.2)%	(46,020	)	(47,650	)	1,630	(3.4)%

Interest expense is comparable to prior period for the three months ended September 30, 2013.

Interest expense decreased $1.6 million for the nine months ended September 30, 2013, as compared to the same period in 2012, primarily due to decreased debt amortization expense of $1.6 million.  See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding long-term debt.

Other Income (Expense)
	Three Months Ended September 30,											Nine Months Ended September 30,
	2013			2012			Variance			% Change		2013			2012			Variance			% Change
Interest income (expense) on regulatory items	$	(87	)	$	(401	)	$	314		(78.3	)%	$	53		$	(715	)	$	768		(107.4	)%
AFUDC-equity	$	632		$	582		$	50		8.6	%	$	1,579		$	1,843		$	(264	)	(14.3	)%
Other income	$	983		$	1,399		$	(416	)	(29.7	)%	$	4,641		$	4,181		$	460		11.0	%
Other expense	$	(982	)	$	(998	)	$	16		(1.6	)%	$	(3,803	)	$	(3,609	)	$	(194	)	5.4	%

Interest income (expense) on regulatory items decreased for the three and nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to $1.2 million and $2.9 million, respectively, of decreases in interest on deferred energy as a result of lower over-collected balances in 2013, offset by $0.7 million and $1.7 million, respectively, of decreases in carrying charges on solar conservation programs and by $0.2 million and $0.4 million, respectively, of decreases in interest income due to lower regulatory asset balances. See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details of deferred energy balances.    

AFUDC-equity increased slightly for the three months ended September 30, 2013 compared to the same period in 2012, primarily due to an increase in base construction projects. AFUDC-equity decreased slightly for the nine months ended September 30, 2013 compared to the same period in 2012, primarily due to the completion of the NV Energize.

Other income decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to higher refunds in 2012, offset by several items, none of which were individually material.

Other income increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $1.9 million insurance settlement in 2013, offset by $1.1 million settlement with CA ISO in 2011 recognized in 2012, and higher refunds in 2012. See Note 3, Regulatory Actions, FERC Matters, in the Notes to Financial Statements in the 2012 Form 10-K.

Other expense decreased for the three months ended and increased for the nine months ended September 30, 2013, compared to the same period in 2012, by several items, none of which are individually material.

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ANALYSIS OF CASH FLOWS

Cash From Operating Activities

SPPC’s net cash flows from operating activities were $156.9 million and $146.9 million for the nine months ended September 30, 2013 and 2012, respectively.

The increase in cash from operating activities was primarily due to:

• Reduced coal purchases of $23.4 million;

• Reduced spend on renewable programs of $19.6 million;

• Receipt of approximately $9.0 million in insurance proceeds related to a previous claim;

• Timing of payments for property taxes of $4.6 million; and

• Timing of payments for energy costs of $4.5 million.

The increase in cash from operating activities was partially offset by:

• Under-collection of energy costs resulting from adjustments to BTER rates and higher energy costs of $92.4 million, offset by reduced refunds to customers of $42 million;

• Reduced EEPR collections of $5.8 million; and

• Increased funding of the retirement plan in 2013 of $2.9 million.

Cash Used By Investing Activities

SPPC’s net cash used by investing activities were $(90.4) million and $(127.8) million for the nine months ended September 30, 2013 and 2012, respectively.

The decrease in cash used by investing activities was primarily due to:

• Reduced capital expenditure for the NV Energize project of $91.0 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $17.4 million.

Cash Used By Financing Activities

SPPC’s net cash flows used by financing activities were $(43.2) million and $(22.6) million for the nine months ended September 30, 2013 and 2012, respectively.

The increase in cash used by financing was primarily due to:

• Maturity of $250 million of 5.45% General and Refunding Mortgage Notes, Series Q debt ; and

• Increased dividends to NVE of $20 million.

The increase in cash used by financing was partially offset by:

• The issuance of $250 million of 3.375% General and Refunding Mortgage Notes, Series T debt.

SPPC paid dividends of $40 million and $20 million to NVE during the nine months ended September 30, 2013 and 2012, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

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

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Available Liquidity as of September 30, 2013 (in millions)
	SPPC
Cash and Cash Equivalents	$	84.1
Balance available on Revolving Credit Facility(1)	243.7
	$	327.8

⁽¹⁾  As of November 6, 2013, SPPC had approximately $244.0 million available under its revolving credit facility which includes reductions for letters of credits.

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 further debt maturities for the remainder of 2013.   As of November 6, 2013, SPPC has no borrowings on its revolving credit facility, not including letters of credit.  In 2012, SPPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below).  In 2012, SPPC did not experience any limitations in the credit markets, nor do we expect any significant limitations for the remainder of 2013.  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 prior years, SPPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As SPPC has transitioned to slower growth, the amount of capital expenditures required has declined.  SPPC’s investment in generating stations in the past several years and more stable energy markets have positioned SPPC to better manage and optimize its resources.  As a result, SPPC anticipates that it will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility.  Furthermore, with significant investments in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL, and a decrease in capital expenditures, SPPC expects to generate free cash flow in 2013; however, SPPC’s cash flow may vary from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.   To meet long term maturing debt obligations, SPPC may use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt, or capital contributions from NVE.   

However, if energy costs rise at a rapid rate, 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 maintain sufficient liquidity under such circumstances, SPPC may be required to delay capital expenditures, refinance debt, or receive capital contributions from 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.  Additionally, 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.

During the nine months ended September 30, 2013, SPPC paid dividends to NVE of approximately $40.0 million.  On November 6, 2013, SPPC declared a dividend to NVE of $37.0 million. 

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, environmental compliance, improvement, and maintenance of facilities.

During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in SPPC’s 2012 Form 10-K, except that in June 2013, SPPC entered into a long-term capital lease for a solar array facility, still subject to commercial operation and approval by the PUCN.  The contract requires SPPC to make annual payments of approximately $3.0 million per year for a twenty year period.  However, SPPC has the option to terminate the lease and purchase the facility on or after the sixth anniversary of the commercial operation date of the facility for approximately $20.0 million. 

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Financing Transactions

In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013. 

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 September 30, 2013, 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 September 30, 2013, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority (1) to issue additional long-term debt securities of up to $350 million; (2) to refinance up to approximately $348.3 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million.  In May 2013, NPC and SPPC filed a joint financing application with the PUCN, see Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details.

b. Financial covenants within SPPC’s financing agreements - Under the SPPC Credit Agreement, 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 1.00.  Based on financial statements for the period ended September 30, 2013, SPPC was in compliance with this covenant and could incur up to $1.1billion of additional indebtedness.

All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently 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 $3.7 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 and NVE’s 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 the SPPC Indenture.

The SPPC Indenture creates a lien on substantially all of SPPC’s properties in Nevada.  As of September 30, 2013, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $860 million of additional General and Refunding Mortgage Securities as of September 30, 2013.  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.  Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.

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

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Credit Ratings

The liquidity of SPPC, the cost and availability of borrowing by SPPC under the SPPC Credit Agreement, 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.  On May 22, 2013, Moody’s upgraded SPPC’s ratings.  On May 30, 2013, Fitch and S&P upgraded SPPC’s rating outlook from Stable to Positive.  SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P.  The senior secured debt credit ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
SPPC	Sr. Secured Debt	BBB+*	A3*	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 and S&P’s rating outlooks are Positive, while Moody’s rating outlook is Stable for SPPC.  

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 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 value as of September 30, 2013, 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 and normal sales 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.

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.

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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 in Note 6, Long Term Debt of the Notes to Financial Statements in the 2012 Form 10-K,  SPPC’s Financing Transactions, the availability under the SPPC’s revolving credit facility 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 facility shall at no time exceed 50% of the total commitments then in effect under the credit facility.  Currently, there are no negative mark-to-market exposures that would impact borrowings of SPPC.  If deemed prudent, SPPC may 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 their respective 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.

Change of Control Provisions; Consent of Lenders

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination.  The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of SPPC.  As a result, SPPC will be required to offer to purchase approximately $951.7 million of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, SPPC is unable to determine the extent to which holders of these debt securities will accept such tender offers.  The average interest rate under these debt securities is approximately 5.51% for SPPC.  To the extent that debt securities are tendered pursuant to the required tender offers, SPPC intends to fund the purchases using a combination of internal funds, SPPC’s revolving credit facility or the issuance of long-term debt. Furthermore, SPPC was required to obtain consents from lenders under the terms of its revolving credit facility before consummating the MidAmerican Merger. In November 2013, SPPC amended its revolving credit facility to permit the MidAmerican Merger.

RECENT PRONOUNCEMENTS

See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements, and Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements in the 2012 Form 10-K for discussion of accounting policies and recent pronouncements.

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ITEM 3.                     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of September 30, 2013, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity.  Such instruments are fixed and variable rate debt.  Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands):

	2013
	Expected Maturities
	2013		2014			2015			2016			2017		Thereafter			Total			Fair Value
Long-Term Debt
NVE
Fixed Rate	$	—	$	195,000		$	—		$	—		$	—	$	315,000		$	510,000		$	561,613
Average Interest Rate	—		2.56		%	—			—			—		6.25		%	4.84		%	—
NPC
Fixed Rate	$	—	$	125,000		$	250,000		$	210,000		$	—	$	2,545,000		$	3,130,000		$	3,677,189
Average Interest Rate	—		7.38		%	5.88		%	5.95		%	—		6.47		%	6.42		%	—
Variable Rate	$	—	$	—		$	—		$	—		$	—	$	75,675		$	75,675		$	72,637
Average Interest Rate	—		—			—			—			—		0.54		%	0.54		%	—
SPPC
Fixed Rate	$	—	$	—		$	—		$	450,000		$	—	$	501,742		$	951,742		$	1,066,865
Average Interest Rate	—		—			—			6.00		%	—		5.07		%	5.51		%	—
Variable Rate	$	—	$	—		$	—		$	—		$	—	$	214,675		$	214,675		$	185,176
Average Interest Rate	—		—			—			—			—		0.54		%	0.54		%	—
TOTAL DEBT	$	—	$	320,000		$	250,000		$	660,000		$	—	$	3,652,092		$	4,882,092		$	5,563,480

Commodity Price Risk

                See the 2012 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk.  No material changes in commodity risk have occurred since December 31, 2012.

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 $50 million as of September 30, 2013, which compares to balances of $98.6 million at March 30, 2013 and $116.6 million at June 30, 2013. The decrease from March 30, 2013 and June 30, 2013 is primarily due to expiring contracts.

ITEM 4.     CONTROLS AND PROCEDURES 

(a)     Evaluation of disclosure controls and procedures. 

NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of September 30, 2013, the registrants’ disclosure controls and procedures were effective.

(b)     Change in internal controls over financial reporting.

There were no changes in the registrants’ internal controls over financial reporting in the third quarter of 2013 that have materially affected, or are reasonably likely to materially affect, the registrants’ internal controls over financial reporting.

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PART II  -  OTHER INFORMATION

ITEM 1.                      LEGAL PROCEEDINGS

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 8, Commitments and Contingencies of the Condensed Notes to Financial Statements for further discussion of other legal matters.

ITEM 1A.   RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC).  The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2012 Form 10-K.  The risks and uncertainties described below are not the only ones we face.  Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2012 Form 10-K, and quarterly reports for NVE, NPC and SPPC on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013.

ITEM 2.     UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.     DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.     MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.     OTHER INFORMATION

None. 

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ITEM 6.     EXHIBITS    

(a)     Exhibits filed with this Form 10-Q:

(10) Nevada Power Company:

10.1 Collective Bargaining Agreement effective September 24, 2013 through August 31, 2017, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396.

(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.:

Lands of Sierra Inc., a Nevada corporation

Nevada Power Company d/b/a NV Energy, a Nevada corporation

NVE Insurance Company, Inc., a Nevada corporation

Sierra Gas Holdings Company, a Nevada corporation

Sierra Pacific Power Company d/b/a NV Energy, a Nevada corporation

Nevada Power Company:

Commonsite, Inc., a Nevada corporation

Nevada Electric Investment Company, a Nevada corporation

Sierra Pacific Power Company:

GPSF-B Inc. , a Delaware corporation
Piñon Pine Corporation, a Nevada corporation
Piñon Pine Investment Company, a Nevada corporation
	Piñon Pine Company, L.L.C., a Nevada limited liability company

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(31)    NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

31.1	Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3	Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4	Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.5	Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.6	Certification of Principal 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 Principal Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.3	Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.4	Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.5	Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.6	Certification of Principal 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

76

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

		NV Energy, Inc.
		(Registrant)
Date:	November 6, 2013	By:	/s/ Michael W. Yackira
			Michael W. Yackira
			President and Chief Executive Officer
			(Principal Executive Officer)
Date:	November 6, 2013	By:	/s/ E. Kevin Bethel
			E. Kevin Bethel
			Vice President and Chief Financial Officer
			(Principal Financial Officer)
		Nevada Power Company d/b/a NV Energy
		(Registrant)
Date:	November 6, 2013	By	/s/ Michael W. Yackira
			Michael W. Yackira
			President and Chief Executive Officer
			(Principal Executive Officer)
Date:	November 6, 2013	By:	/s/ E. Kevin Bethel
			E. Kevin Bethel
			Vice President and Chief Financial Officer
			(Principal Financial Officer)
		Sierra Pacific Power Company d/b/a NV Energy
		(Registrant)
Date:	November 6, 2013		/s/ Michael W. Yackira
			Michael W. Yackira
			President and Chief Executive Officer
			(Principal Executive Officer)
Date:	November 6, 2013	By:	/s/ E. Kevin Bethel
			E. Kevin Bethel
			Vice President and Chief Financial Officer
			(Principal Financial Officer)

77

EX-10.1

Exhibit 10.1

Collective Bargaining Agreement

NV Energy

6226 W Sahara Ave

Las Vegas, NV 89151-0001

(702) 402-5000

Effective 09/24/2013 - 08/31/2017

IBEW Local 396

3520 Boulder Highway

Las Vegas, NV 89121

(702) 457-3011

NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

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	TIME OFF	31
ARTICLE NO. 12	FROZEN SICK LEAVE / DISABILITY	33
ARTICLE NO. 13	EMPLOYEE BENEFIT PROGRAMS	38
ARTICLE NO. 14	LEAVES OF ABSENCE	46
ARTICLE NO. 15	GENERAL PROVISIONS	49
ARTICLE NO. 16	WORKING RULES	51
ARTICLE NO. 17	TERM OF AGREEMENT	54
EXHIBIT III	CHECK OFF AUTHORIZATION	56
EXHIBIT IV	TEMPORARY LAYOFF PROVISIONS	57
EXHIBIT V	MEDICAL, DENTAL AND VISION PLANS	578
CLERICAL
ARTICLE NO. 4	UNION ACTIVITY	62
ARTICLE NO. 5	STATUS DESIGNATION	63
ARTICLE NO. 6	WORKING HOURS AND RATES OF PAY	65
Alternative Shift Agreements	FOUR-TEN HOUR SHIFT SCHEDULE	67
EXHIBIT I	JOB CLASSIFICATION DESCRIPTIONS	73
TRANSMISSION & DISTRIBUTION
ARTICLE NO. 4	UNION ACTIVITY	78
ARTICLE NO. 6	WORKING HOURS AND RATES OF PAY	80
ARTICLE NO. 16	WORKING RULES	85
EXHIBIT I	JOB CLASSIFICATION DESCRIPTIONS	86
Alternative Shift Agreements	FOUR-TEN HOUR SHIFT SCHEDULE	102

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GENERATION
ARTICLE NO. 4	UNION ACTIVITY	109
ARTICLE NO. 6	WORKING HOURS AND RATES OF PAY	110
Alternative Shift Agreements	TWELVE-HOUR SHIFT SCHEDULE	114
Alternative Shift Agreements	FOUR-TEN HOUR SHIFT SCHEDULE	119
Alternative Shift Agreements	THIRTY-SIX FOR FORTY	122
ARTICLE NO. 16	WORKING RULES	125
EXHIBIT I	JOB CLASSIFICATION DESCRIPTIONS	126
LOA	CHARLES LENZIE / HARRY ALLEN COMPLEX AGREEMENT	138
LOA	ELECTRIC SYSTEM CONTROL CENTER OPERATORS	142
SUPPLY CHAIN
JOB CLASSIFICATIONS AND WAGES		154

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AGREEMENT

This Agreement, made and entered into as of September 24, 2013, 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 (CLASSIFICATIONCLASSIFICATION 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.

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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.

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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.

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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.

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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.

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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.

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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.

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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, an employee is qualified to perform any position, in the CBA, which the employee has successfully occupied with 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, can exercise the requisite skills for the position as demonstrated to the Company’s reasonable satisfaction through testing developed by the Company. Under no circumstances will an employee be able to bump into a position that provides a higher wage, unless that position was successfully held in the Company. For employees in Generation or Combined Cycle Generation, 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, time off, and benefits. There will be no probationary period.

MPAT EMPLOYEE ACCEPTING A REPRESENTED POSITION: Any MPAT employee of the Company who accepts a position in the bargaining unit will establish a new date of seniority. The Company seniority date for such an employee shall become the date when the employee begins work in the represented position. There shall be no bridging of time for time spent in the MPAT position.

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.

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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 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.

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

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

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eligible to retire under the traditional retirement plan component and receive post retirement medical benefits.

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.

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Collective Bargaining Agreement

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EXHIBIT A

ARTICLE NO. 5.5

Severance Flow Chart

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NV Energy - IBEW L396

Collective Bargaining Agreement

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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.

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Collective Bargaining Agreement

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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, SHIFTSHIFT - as defined by Article 6.1 AND CLASSIFICATIONCLASSIFICATION 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.

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Collective Bargaining Agreement

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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 24, 2013 through August 31, 2017 ....................$1.45 per hour

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

September 24, 2013 through August 31, 2017 ………………$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, paid time off 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

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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 inGeneration)

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

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NV Energy - IBEW L396

Collective Bargaining Agreement

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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.

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NV Energy - IBEW L396

Collective Bargaining Agreement

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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.

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Collective Bargaining Agreement

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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 24, 2013 through August 31, 2017……………..$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.

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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. 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.

If a subsequent vacancy occurs after a position has been posted or awarded in the same department and for the same position, the Company shall utilize the original selection list generated during the staffing process to issue subsequent job award(s) provided that any subsequent job award(s) are issued within ninety (90) days of the closing of the original job posting.

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.

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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.

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.

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7.8 TRIAL PERIODTRIAL 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 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 REHIRED 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 total time employed (i.e. calendar days on payroll) with the Company for purposes of Company seniority and all related benefits other than retirement benefits in which case the Plan document control.

Any former employees re-hired after September 24, 2013 shall not be eligible to have their time bridged. The employee shall be considered a new hire for purposes of Company seniority.

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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

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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.

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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 WEATHERINCLEMENT 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

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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.

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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	2014	2015	2016	2017
New Year’s Day	Jan 1	Jan 1	Jan 1	Jan 2
Martin L King Day	Jan 20	Jan 19	Jan 18	Jan 16
Presidents Day	Feb 17	Feb 16	Feb 15	Feb 20
Memorial Day	May 26	May 25	May 30	May 29
Independence Day	July 4	July 3	July 4	July 4
Labor Day	Sept 1	Sept 7	Sept 5	TBD
Veterans Day	Nov 11	Nov 11	Nov 11	TBD
Thanksgiving Day	Nov 27	Nov 26	Nov 24	TBD
Thanksgiving Friday	Nov 28	Nov 27	Nov 25	TBD
Christmas Eve	Dec 24	Dec 24	Dec 23	TBD
Christmas	Dec 25	Dec 25	Dec 26	TBD

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 UNSCHEDULED ABSENCE 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 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

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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.

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ARTICLE NO. 11

Time Off

INTRODUCTION

This Article is amended and restated as of 9/24/2013.

Effective December 16, 2013, employees will receive paid time off (“PTO”) to use for vacation, sick leave, bereavement leave, family illness or activities, personal appointments, and any other time the employee would like off. Employees will continue to utilize the vacation and sick leave provisions contained in the prior Collective Bargaining Agreement for the remainder of the 2013 payroll year.

11.1 USE/ACCRUAL: Employees can use PTO for vacation, sick leave, family illness or activities, personal appointments and any other time the employee would like off.

PTO is accrued on an annual basis in accordance with the payroll calendar year. Allotment for regular employees shall be based on the years of service that will be completed within the payroll calendar year. Allotment for employees who terminate prior to the end of the payroll year will be prorated at the time of termination to the actual number of hours used at the time of termination. Any remaining allotment of PTO hours shall be paid at termination of employment, at the employee's current base rate. Except where otherwise required by law, the Company has the right to withhold any PTO if the employee has any outstanding obligations, if the employee has overused their accrued PTO, or if the employee has not returned Company property.

11.2 FIRST TWO (2) CALENDAR YEARS OF EMPLOYMENT: Full-time probationary and regular employees shall earn PTO during the first two (2) calendar years of their employment according to the month in which they are hired as follows:

Month Hired	PTO Hours
January	176 hours
February	162 hours
March	148 hours
April	134 hours
May	120 hours
June	106 hours
July	92 hours
August	78 hours
September	64 hours
October	50 hours
November	36 hours
December	22 hours

Example:

If an employee is hired March 2014, the employee is granted 148 hours PTO to be used by payroll year-end subject to the carryover provisions in Article 11.7. In the beginning of the payroll calendar year of the second year of employment, 176 hours of PTO will be front loaded to be used by payroll year-end subject to the carryover provisions in Article 11.7.

11.3 ACCRUED TIME OFF: Full-time regular employees earn PTO according to the following schedule:

	PTO Hours
2 years through 5 years	176 hours
6 years through 12 years	216 hours

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13 years through 20 years	256 hours
21 years through 30 years	296 hours
31 years and above	336 hours

Allotment is based on the years of service that will be completed within the calendar year.

11.4 HOLIDAY WHILE ON PTO: If a holiday is observed by the Company on a work day within an employee's PTO period, the holiday shall not be considered as PTO.

11.5 INCREMENTS: PTO can be used in quarter-hour (15 minute) increments. PTO shall be paid at the straight-time rate of pay.

11.6 DEPARTMENTAL POLICIES: Each department will develop standards and procedures for scheduling PTO using, at a minimum, the following considerations:

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

11.7 CARRYOVER: Employees are able to carry over up to forty (40), plus any fractional hours, of unused PTO hours from payroll year to payroll year (i.e., 40.54 hours). Unused amounts over forty (40) hours will be forfeited if not used before the end of the payroll year. However, employees hired before 9/24/13 will be allowed to roll over any unused PTO amounts over forty (40) hours into their frozen sick leave banks (as provided in Article 12.1) at the end of the payroll year in 2014, 2015 and 2016.

11.8 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 11.6 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.

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ARTICLE NO. 12

Frozen Sick Leave / Disability

This Article is amended and restated as of 9/24/2013.

12.1 FROZEN SICK LEAVE: Employee’s sick leave balances will be frozen (“frozen sick leave”) at the end of the 2013 payroll year. Any such balance would continue to be carried over from payroll year to payroll year until qualified retirement from the Company. At such time, any remaining frozen sick leave will be converted as provided in Article 13.

Frozen sick leave may only be used: (1) for the three (3) day eligibility period to commence Short Term Disability (“STD”) benefits; (2) to supplement STD pay; or (3) in connection with an approved leave of absence under the FMLA, ADA or any other approved leave of absence.

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 may be eligible for light duty assignments at the discretion of the Company, 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 (JOBJOB 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.

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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 PTO or frozen sick leave, and upon exhaustion of such PTO or frozen 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 PTO or frozen sick leave.

▪ 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

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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 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 BENEFITSBENEFITS	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.

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▪ No disability payments for an illness shall be made until at least a three (3) business days waiting period has been observed. An employee must use available PTO or frozen sick leave to satisfy the waiting period before taking the waiting period unpaid.

▪ 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 may use PTO or their frozen 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 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.

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ARTICLE NO. 13

Employee Benefit Programs

This Article is amended and restated as of September 24, 2013, except as otherwise set forth herein.

Employees will continue to utilize the medical benefits outlined in the prior Collective Bargaining Agreement for the remainder of the 2013 calendar year.

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. Health Savings Account (“HSA”) w/ Healthy Living Program

2. Health Reimbursement Account (“HRA”) w/ Healthy Living Program

3. Health Reimbursement Account (“HRA”)

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

The plan design for these options is more fully described in Exhibit “V.”

OPEN ENROLLMENT: Initial open enrollment due to a change in plan options will be in November/December 2013. 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 HRA w/ Healthy Living Program with employee only coverage.

EMPLOYEE CONTRIBUTIONS: The rates for medical coverage will be actuarially determined each plan year, based on previous claims experience. 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.

EMPLOYEES LIVING OUTSIDE THE HEALTHY LIVING PROGRAM SERVICE AREA: Employees living in the Healthy Living Program service area are defined as employees living in Las Vegas, North Las Vegas, Henderson and Blue Diamond. Employees living outside these areas may still elect to enroll in a Healthy Living Program plan.

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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:

▪ 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 separate lifetime 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.

13.2 WELLNESS PROGRAM

Employees enrolled in a Healthy Living Program HRA or Healthy Living Program HSA plan, or employees living outside the Healthy Living Program Service area as defined above enrolled in the HRA plan, on January 1, 2014 will receive annual incentive amounts for participating in the Company’s healthy living incentive program as described below. Employees hired in time to complete the healthy living incentive program will be eligible for the associated incentive the next year. Employees will receive an incentive of $300 - employee only coverage; $600 - employee plus children or plus spouse; or $900 - employee plus family, if they and their spouse (if spouse is covered on Company plan) complete the Company’s biometric screening, online health risk assessment, select a Healthy Living Program Primary Care Physician (or a primary care physician for those living outside of the Healthy Living Program service area) and if they cooperate with Aetna/Healthy Living Program’s disease management outreach. Employees will receive an incentive of $300 - employee only coverage; $600 - employee plus children or plus spouse; or $900 - employee plus family, if they are tobacco free or successfully complete a tobacco cessation program. Dependents, other than a covered spouse, are not required to participate in the healthy living incentive program in order for the employee to receive the incentive(s).

The healthy living incentive(s) will be distributed to employees as a payroll credit. The credit will be divided equally throughout the payroll year and distributed semi-monthly.

Individual results from these wellness programs are provided only to the enrolled employee and are kept completely confidential. No individual results will be shared with the Company except as necessary to obtain the healthy living incentive(s). Results are collected by a third party and will only be shared with the Company in aggregate (total population health) to assist with on-going health and wellness program planning.

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Collective Bargaining Agreement

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13.3 HARDSHIP FUND

If an employee undergoes a financial hardship related to medical expenses, they may make a request to the Company to request additional Company-paid account funding into a Flexible Spending Account (“FSA”) as follows:

(a)Employee must have reached the out of pocket maximum for a minimum of two (2) years in a row.

(b)The request is made in writing to the employee’s HR Business Partner.

(c)Employees may be eligible to apply every two (2) years provided they have reached the out of pocket maximum in each of the previous two (2) years.

(d)It is the Company’s decision to grant or deny the additional funding and the Company’s decision is not subject to the grievance process. However, any denial must first be discussed with the Union.

(e)Each request will be considered separately by the Company.

If the request is granted, the employee will be given a one-time deposit into an FSA of $1,000 for employee only coverage, $1,500 for employee plus children or plus spouse, or $2,000 for employee plus family coverage.

13.4 DAY CARE DEPENDENT CARE FLEXIBLE SPENDING ACCOUNT (DCFSA)/HEALTH CARE FLEXIBLE SPENDING ACCOUNT (HCFSA)

The Company will, during the term of this Agreement, provide a Day Care 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.

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.

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Collective Bargaining Agreement

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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 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

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$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.

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 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.

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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.

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

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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 1^st month following date of hire. 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.

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Collective Bargaining Agreement

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13.11 RETIREMENT ONLY HEALTH REIMBURSEMENT ACCOUNTS (“RRA”):

1.Effective January 1, 2014, employees who will complete 10, 15, 20, etc. years of continuous service with the Company will receive a lump sum deposit into a RRA upon qualified retirement with the Company as outlined below:

•10 years: $1,250

•15 years: $1,500

•20 years: $1,750

•25 years: $2,000

•30 years+: $2,500

The RRA will only be able to be utilized upon qualified retirement from the Company.

2.Effective January 1, 2014, employees with frozen sick leave banks, as outlined in Article 12.1, who retire under the qualified retirement plan shall have their frozen sick leave banks converted at the rate of pay at retirement into a RRA, under the following tiers, as follows:

• Frozen sick leave 0-250: All hours are forfeited at retirement.

• Frozen sick leave hours of 251-500: 50% of the hours will be converted at the employee's base rate at the time of qualified retirement. For example, an employee retiring with 450 frozen sick leave hours at the base rate of $35.00 would receive $3,500 in his RRA as follows:

0-250 hours	=		$0
251-450 hours	=	200 hours x $35.00 x 50%	= $3,500
Total Contribution			= $3,500

• Frozen sick leave hours over 500: All hours over 500 hours will be converted at the employee's base rate at the time of qualified retirement (hours under 500 will be converted as outlined in the calculation below). For example, an employee retiring with 1,200 frozen sick leave hours at the base rate of $35.00 would receive $28,875 in his RRA.

0-250 hours	=		$0
251-500 hours	=	250 hours x $35.00 x 50%	= $4,375
501-1200 hours	=	700 hours x $35.00	= $24,500
Total Contribution			= $28,875

3.Employees who separate from the Company other than for a qualified retirement will forfeit all frozen sick leave hours.

4.Effective January 1, 2014, employees will no longer receive creditable service time for frozen sick leave, upon qualified retirement.

5. For employees hired before September 24, 2013, an employee can forego the above continuous service bonus described in Article 13.11(1) and instead receive a paid time off bonus of forty (40) hours in the year they complete ten (10) years of continuous service and each five (5) years of continuous service thereafter.  Any such continuous service bonus 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).  Any paid time off received under this provision will be subject to the carryover rules set forth in Article 11 and must be used prior to separation with the Company or such time will be forfeited and not paid out upon separation.  This section will be eliminated effective August 31, 2017.

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13.2 SAFETY BONUS:   The Company and Union agree to mutually confer and determine safety bonus criteria prior to December 31, 2013 and any such criteria can be changed from year to year upon mutual agreement of the parties.

• If earned, 1% lump sum (based on total hours worked) will be paid by April 15, 2015.

• If earned, 1% lump sum (based on total hours worked) will be paid by April 15, 2016.

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Collective Bargaining Agreement

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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, paid time off 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, 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.

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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 paid time off 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 SUBPOENASUBPOENA: 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 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.

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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. Paid time off 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 approved FMLA leave are required to use any available frozen sick leave or paid time off. However, an employee may commence taking FMLA leave unpaid while retaining 40 hours accrued paid time off. Employees may use frozen sick leave for FMLA leave for the care of another and would be required to use such leave prior to taking unpaid leave.

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Collective Bargaining Agreement

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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

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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).

15.9 LETTERS OF AGREEMENT: The Company and Union will review Letters of Agreement at the expiration of each Collective Bargaining Agreement. If at the expiration of the Collective Bargaining Agreement, Letters of Agreement are not agreed to or incorporated into the contract, or kept active due to the individual nature or specific time commitment contained in the Letter, they will be terminated.

Letters of Agreement are only binding if they are signed by the Labor Relations Director or Labor Manager for the Company and the Business Manager or Business Representative for the Union.

Should either the Company or Union find letters of agreement that were inadvertently not discussed during negotiations, they shall meet to discuss the viability of the letter.

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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.

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16.6 TOOLS, EQUIPMENT AND WORKWORK 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 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

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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 (CLASSIFICATIONCLASSIFICATION 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.

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ARTICLE NO. 17

Term of Agreement

17.1 DURATION: This Agreement shall take effect on September 24, 2013, and shall continue in effect for the term September 24, 2013 through August 31, 2017, 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 September 1, 2011 is superseded by this Agreement dated as of September 24, 2013 except as otherwise expressly provided herein, the provisions of this Agreement shall be effective September 24, 2013.

17.6 WAGE REOPENER: The no strike clause and all other provisions of Article 1.2 CONTINUITY OF SERVICE will remain in full force and effect for the entire term of the Agreement. The parties agree that it will meet and confer concerning wages only for the fourth year of the Agreement by May 1, 2016 and no other terms, conditions or clauses of the Agreement will be re-opened including the no strike clause and all other provisions of Article 1.2 CONTINUITY OF SERVICE.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement effective September 24, 2013.

NV Energy

/s/ Alice A. Cobb

Alice A. Cobb

Senior Vice President, Human Resources & IT

Local Union 396 of the International Brotherhood

of Electrical Workers (AFL-CIO)

/s/ Jesse Newman

Jesse Newman

Business Manager/Financial Secretary

IBEW Local 396

Negotiating Committee
NV Energy	IBEW Local 396
David Lonergan	Jesse Newman
Ryan Bellows	Jeremy (Frog) Newman
Trudy Haszlauer	Casey Wills
	Marc Orr
	Shannon Skinner
	Wayne Baca

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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 ___________________________________________________________________________________

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EXHIBIT IV

TEMPORARY LAYOFF PROVISIONSPROVISIONS

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.

PAYPAY: 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.

PTO: No adjustment to PTO 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 PTO accrual shall be adjusted and treated as any other leave. Employees in layoff status and unable to use their PTO allotment for that year, the unused PTO shall be automatically carried over to the next year.

SHORT-TERM DISABILITY: Employees will not be eligible to use short-term disability benefits 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.

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

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

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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.

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EXHIBIT V

MEDICAL, DENTAL AND VISION PLANS

(Amended 9/26/13)

IBEW Local Union 396 Medical and Prescription Drug deductibles and coinsurance apply to the Out-of-Pocket Maximum
	HRA		HSA
	In-Network	Out-of-Network	In-Network	Out-of-Network
Annual Deductible	$1,000 Individual, $2,000 Family	$2,000 Individual, $4,000 Family	$1,250 Individual, $2,500 Family	$2,500 Individual, $5,000 Family
Plan Generally Pays	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Out-of-Pocket Maximum (Annual)	$2,000 Individual, $5,000 Family	$4,000 Individual, $10,000 Family	$2,000 Individual, $5,000 Family	$4,000 Individual, $10,000 Family
Lifetime Maximum	Unlimited (unless otherwise indicated)
Employer Account Contributions
Account-Based Contribution	$750 Individual, $1,500 Family (2014) - all Employee Participants; $750 individual, $1,500 family (2015, 2016, 2017) - all Healthy Living Program Employee Participants; $500 Individual, $1,000 Family (2015, 2016, and 2017) - all non-Healthy Living Program Employee Participants
Healthy Living Incentive - required participation in Healthy Living Program & Biometric Screening & Online Health Risk Assessment	$300 Individual, $600 Individual + Spouse or Child(ren), $900 Family (Issued as payroll credit)
Healthy Living Incentive - required participation in Healthy Living Program (Tobacco Free Screening or Completion of Cessation Program)	$300 Individual, $600 Individual + Spouse or Child(ren), $900 Family (Issued as payroll credit)
Other
Free Office Visits (covered at 100%) to Healthy Living Program PCP(s) for Employee / Spouse/Domestic Partner	2 Employee, 2 Spouse/Domestic Partner (2014, 2015, 2016, 2017) - HRA Plan Participants participating in Healthy Living Program only * One additional Free Annual Office Visit (covered at 100%) to Healthy Living Program PCP(s) for Employee / Spouse/Domestic Partner covered under Plan Preventive Care Benefits for a maximum allowable total of three Free Office Visits (covered at 100%) to Healthy Living PCP(s) per year.
Routine Care
Physician Charges (Office Visit, Inpatient, Outpatient) *also see Other	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Specialist Charges	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Preventive Care
Well Child Care (Includes immunizations)	100% no Co-pay, no Deductible	Not covered	100% no Co-pay, no Deductible	Not covered
Well Adult Care (OB/GYN, Mammogram, PAP, Prostate exam)	100% no Co-pay, no Deductible	Not covered	100% no Co-pay, no Deductible	Not covered
Women’s Preventive Services (as outlined in the Affordable Care Act)	100% no Co-pay, no Deductible	Not covered	100% no Co-pay, no Deductible	Not covered
Maternity and Family Services
Physician Charges	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Hospitalization & Newborn Nursery Care	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Sterilization (Includes tubal ligation & vasectomy	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Infertility Treatment * (Diagnostics & treatment of underlying condition only)	90% after Deductible ** (For diagnosis & treatment, 6 courses of treatment lifetime max)	70% after Deductible ** (For diagnosis & treatment, 6 courses of treatment lifetime max)	80% after Deductible ** (For diagnosis & treatment, 6 courses of treatment lifetime max)	60% after Deductible ** (For diagnosis & treatment, 6 courses of treatment lifetime max)

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Hospital Care
Inpatient Coverage	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Outpatient Coverage (Including surgery)	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Urgent Care	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Emergency Room ***	90% after Deductible	90% after Deductible	80% after Deductible	80% after Deductible

	HRA		HSA
Mental Health and Substance Abuse Care
Inpatient Coverage	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Outpatient Coverage	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Other Medical Care
Allergy testing	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Chiropractic Care (Limited to 20 visits per calendar year) *	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Durable Medical Equipment	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Home Health Care*	90% after Deductible (Limited to 120 days per calendar year)	70% after Deductible (Limited to 120 days per calendar year)	80% after Deductible (Limited to 120 days per calendar year)	60% after Deductible (Limited to 120 days per calendar year)
Hospice Care (Inpatient, Outpatient)	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Complex imaging	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Lab & X-ray	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Physical & Speech Therapy (Outpatient)	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Skilled Nursing Facility	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
Acupuncture & Alternative Medicine *	90% after Deductible ($2,000 Annual Max)	70% after Deductible ($2,000 Annual Max)	80% after Deductible ($2,000 Annual Max)	60% after Deductible ($2,000 Annual Max)
Hearing Aids *	90% after Deductible $1,500 every 5 years	70% after Deductible $1,500 every 5 years	80% after Deductible $1,500 every 5 years	60% after Deductible $1,500 every 5 years
Temporo-Mandibular Joint Disease (TMJ)	90% after Deductible	70% after Deductible	80% after Deductible	60% after Deductible
TMJ Maximum	No limit (excludes appliance therapy)	No limit (excludes appliance therapy)	No limit (excludes appliance therapy)	No limit (excludes appliance therapy)
Prescription Drug
Retail Pharmacy (30 Day Supply)	Generic drugs : 90% after Deductible Preferred Brand drugs: 90% after Deductible Non-Preferred drugs: 90% after Deductible		Generic drugs : 80% after Deductible Preferred Brand drugs: 80% after Deductible Non-Preferred drugs: 80% after Deductible
Mail Order Pharmacy (90 Day Supply, for maintenance drugs only)	Generic drugs : 90% after Deductible Preferred Brand drugs: 90% after Deductible Non-Preferred drugs: 90% after Deductible		Generic drugs : 80% after Deductible Preferred Brand drugs: 80% after Deductible Non-Preferred drugs: 80% after Deductible
Vision
	In Network		Out of Network
Provider Choice	You may use any licensed provider you choose; however your out-of-pocket costs are likely to be less when you use in-network providers, since benefits are based on negotiated fees. In addition, when you stay in network, discounts apply for options and additional materials. When you use out-of-network providers you pay 100% of the claim, then submit the itemized receipt to VSP. Call VSP for information on submitting out-of-network claims.
Examination (once every 12 months based on your last date of service)	$25 Co-pay		Plan pays up to $46 (less applicable co-pays)
Lenses (once every 12 months based on your last date of service)	100% for standard lenses		Plan pays up to $55 for single vision, $75 for bifocal, & $95 for trifocal lenses

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Frames (once every 24 months based on your last date of service)	Plan pays up to $115	Plan pays up to $45
Contact Lenses (elective) (once every 12 months based on your last date of service)	Plan pays up to $250	Plan pays up to $105
Discounts	30% savings on lens options, 20% savings on additional glasses & sunglasses, 15% savings off cost of contact lens fitting & evaluation	Discounts do not apply
Computer Vision Care (Exam & Lenses, once every 12 months) (Frames, once every 24 months)	$10 co-pay for exam, Plan pays up to $80 for frames	Contact VSP
Laser Vision Correction	VSP's Laser Care Program provides discounted access to facilities and surgeons for NVE members. See the Laser Vision Care Learning Source area of VSP's website
Diabetic Eye Care Plus Program (for members with Type 1 and Type 2 Diabetes)	$20 co-pay for follow up diabetic eye care services	Not available
Dental
	In Network		Out of Network
Provider Choice	You may use any licensed provider you choose; however your out-of-pocket costs are likely to be less when you use in-network providers, since benefits are based on negotiated fees. When you use out-of-network providers, you pay your percentage of the reasonable and customary (R&C) amount, plus any amounts the provider charges above R&C.
Annual Deductible	$25 individual, $75 family
Annual Maximum Benefit	$2,000 per person per year
Preventive Services (Includes two (2) cleanings per year)	100% no Deductible		100% of R&C, no Deductible
Basic Care	80% after Deductible		80% of R&C, after Deductible
Oral Surgery	80% after Deductible		80% of R&C, after Deductible
Major Restoration	50% after Deductible		50% of R&C, after Deductible
Orthodontia (Employees and Dependents)	100% after annual deductible; $2,000 lifetime maximum per participant
* In and out-of-network maximum is combined ** Benefits limited to $2,000 per calendar year and $6,000 lifetime *** Non-emergency use of ER is not covered

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CLERICAL

ARTICLE NO. 4

Union Activity

4.3 CONTRACTING WORKWORK:

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.

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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.

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• Shift differential will apply as usual.

• 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 (1 1/2).

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

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CLERICAL

ARTICLE NO. 6

Working Hours and Rates of Pay

6.1 DEFINITIONS:

SHIFTSHIFT: 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 scheduled paid time off 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.

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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.

6.8 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.

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

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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.

Mileage Chart:

Beltway		Clark	Harry Allen	Higgins	Laughlin	Lenzie	North LV	Pearson	Reid	Ryan SVC	SHwk
Beltway SVC	—	12	36.2	37.5	97	33.9	13	7	52	16	38.3
Clark	12	—	36.8	41.4	87.4	34.5	13	14	64	19	38.9
Harry Allen	36.2	36.8	—	68.4	123	5.6	23.6	30.9	31.9	21.2	10
Higgins	37.5	41.4	68.5	—	80.1	66.1	46.2	43.9	92.1	49.8	70.5
Laughlin	97	87.4	123	80.1	—	120	97.2	107	146	104	125
Lenzie	33.9	34.5	5.6	66.1	120	—	21.3	28.6	29.6	18.9	6.6
North LV	13	13	23.6	46.2	97.2	21.3	—	10	51	6	25.7
Pearson	7	14	30.9	43.9	107	28.6	10	—	58	13	33
Reid	52	64	31.9	92.1	146	29.6	51	58	—	45	34
Ryan SVC	16	19	21.2	49.8	104	18.9	6	13	45	—	23.3
Silverhawk	38.3	38.9	10	70.5	125	6.6	25.7	33	34	23.3	—

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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 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

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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.

Paid Time Off/Vacation: The Company recognizes its obligation in accordance with Article 11.1 of the CBA relative to paid time off/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 paid time off/vacation will be subject to availability on the newly assigned shift/location. Management will endeavor to accommodate the original paid time off/vacation request(s) whenever possible, but the employee assumes the risk that their original paid time off/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.

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 paid time off as make-up time with supervisory approval.

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▪ 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.

6.20 FLEXIBLE WEEKEND WORKING HOURS (FOR BILLING AND CREDIT DEPARTMENT ONLY)

With advance supervisory approval, when an employee is scheduled for overtime on a Saturday or Sunday, the employee may begin the start of the shift at any time between 5:00 a.m. and 11:45 a.m. The employee will be compensated at the regular shift schedule wage at the appropriate overtime rate. Without supervisory approval, the employee shall begin the start of the shift as designated by the Company.

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 WAGEWAGE 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.

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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:

◦ 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.

◦ 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.

◦ 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 scheduled paid time off 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 PTO, 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 immediately preceding the holiday or the non-overtime work day immediately following the holiday shall be

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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.

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EXHIBIT I

CLERICAL

JOB CLASSIFICATION DESCRIPTIONS

(Alphabetical)

BILINGUAL CUSTOMER SERVICE REPRESENTATIVE (5276)

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 the use of fluent bilingual (Spanish) speaking skills and extensive customer service skills with a significant degree of decision-making authority. Employees in this classification work on designated shifts as needed.

New hires will be offered bilingual positions with the understanding that they must pass the exam before they start work. If they do not pass the bilingual exam, their job offer will be retracted.

These employees shall receive a $.40 per hour increase over regular CSR wages. The number of Bilingual Customer Service Representative positions shall not exceed the rate of one (1) Bilingual Customer Service Representative to four (4) Customer Service Representatives.

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

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.

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

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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.

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.

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

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.

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-

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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.

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CLERICAL - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/311/14 2.0%	1st Pay Period After 8/31/2015 2.0%
5061	Lead Field Service Rep	1	$29.12	$29.70	$30.29
5161	Field Service Rep	1	$22.97	$23.43	$23.90
	2nd Six Months	2	$24.41	$24.90	$25.40
	3rd Six Months	3	$26.55	$27.08	$27.62
5162	Revenue Protection Investigator	1	$26.71	$27.24	$27.78
	2nd Six Months	2	$27.88	$28.44	$29.01
	3rd Six Months	3	$28.94	$29.52	$30.11
	4th Six Months	4	$30.02	$30.62	$31.23
5174	Senior Customer Service Rep	1	$22.05	$22.49	$22.94
	2nd Six Months	2	$23.04	$23.50	$23.97
	3rd Six Months	3	$24.08	$24.56	$25.05
	4th Six Months	4	$25.16	$25.66	$26.17
	5th Six Months	5	$26.46	$26.99	$27.53
5175	Lead Customer Service Rep	1	$26.11	$26.63	$27.16
5177	Lead Field Srvc Investigator	1	$33.05	$33.71	$34.38
5182	Trainer METER	1	$29.12	$29.70	$30.29
5183	Trainer TSO	1	$29.12	$29.70	$30.29
5270	Reprographic Tech	1	$21.76	$22.20	$22.64
	2nd Six Months	2	$22.54	$22.99	$23.45
	3rd Six Months	3	$23.34	$23.81	$24.29
	4th Six Months	4	$24.09	$24.57	$25.06
	5th Six Months	5	$24.88	$25.38	$25.89
5274	Customer Service Rep	1	$15.58	$15.89	$16.21
5273 p/t	2nd Six Months	2	$16.96	$17.30	$17.65
	3rd Six Months	3	$18.32	$18.69	$19.06
	4th Six Months	4	$19.71	$20.10	$20.50
	5th Six Months	5	$21.09	$21.51	$21.94
5276	Bilingual Customer Service Rep	1	$15.98	$16.30	$16.63
	2nd Six Months	2	$17.37	$17.72	$18.07
	3rd Six Months	3	$18.73	$19.10	$19.48
	4th Six Months	4	$20.11	$20.51	$20.92
	5th Six Months	5	$21.50	$21.93	$22.37

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CLERICAL - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/311/14 2.0%	1st Pay Period After 8/31/2015 2.0%
5371	Lead Support Services	1	$27.37	$27.92	$28.48
5411	Lead Meter Reader	1	$27.50	$28.05	$28.61
5412	Meter Reader	1	$16.77	$17.11	$17.45
5415 p/t	1st Three Months	2	$17.43	$17.78	$18.14
	2nd Three Months	3	$18.00	$18.36	$18.73
	2nd Six Months	4	$18.60	$18.97	$19.35
	3rd Six Months	5	$19.22	$19.60	$19.99
	4th Six Months	6	$19.81	$20.21	$20.61
	5th Six Months	7	$20.42	$20.83	$21.25
	6th Six Months	8	$21.03	$21.45	$21.88
	7th Six Months	9	$21.60	$22.03	$22.47
5416	Technician, Mail & Supply	1	$13.99	$14.27	$14.56
	2nd Six Months	2	$15.23	$15.53	$15.84
	3rd Six Months	3	$16.48	$16.81	$17.15
	4th Six Months	4	$18.03	$18.39	$18.76
	5th Six Months	5	$19.85	$20.25	$20.66

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T & D

ARTICLE NO. 4

Union Activity

4.3 T & D CONTRACTING WORKWORK:

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 WORKWORK - 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 WORKWORK - 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.

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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.

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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.

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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 scheduled paid time off 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

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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.

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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	—
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

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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.

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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).

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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. Must have and maintain a Class A Commercial Driver’s License (CDL) in the State of Nevada. The Company will be responsible for the cost of any physical and license renewal fees.

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

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general office clerical work as required. Performs other related work for which employee is capable and qualified to perform as assigned.

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.

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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. 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

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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.

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.

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.

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.

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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.

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.

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

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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. 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.

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.

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.

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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.

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

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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.

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

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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.

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.

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.

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.

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

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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. Must have and maintain a Class A Commercial Driver’s License (CDL) in the State of Nevada. The Company will be responsible for the cost of any physical and license renewal fees.

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. Must have and maintain a Class A Commercial Driver’s License (CDL) in the State of Nevada. The Company will be responsible for the cost of any physical and license renewal fees.

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.

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

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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.

UTILITY DESIGN COORDINATOR I (3107)

This 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 simple 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.

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Demonstrated proficiency in AUTOCAD is required. 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.

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
3102	Rodman Chainman	1	$24.02	$24.50	$24.99
	2nd Six Months	2	$26.29	$26.82	$27.36
	3rd Six Months	3	$26.50	$27.03	$27.57
	4th Six Months	4	$27.84	$28.40	$28.97
	5th Six Months	5	$29.25	$29.84	$30.44
3103	Tech I, Mapping	1	$22.77	$23.23	$23.69
	2nd Six Months	2	$23.34	$23.81	$24.29
	3rd Six Months	3	$23.89	$24.37	$24.86
	4th Six Months	4	$24.50	$24.99	$25.49
	5th Six Months	5	$25.10	$25.60	$26.11
	6th Six Months	6	$25.74	$26.25	$26.78
	7th Six Months	7	$26.38	$26.91	$27.45
3104	Tech II, Mapping	1	$26.78	$27.32	$27.87
	2nd Six Months	2	$27.34	$27.89	$28.45
	3rd Six Months	3	$27.86	$28.42	$28.99
	4th Six Months	4	$28.43	$29.00	$29.58
	5th Six Months	5	$29.00	$29.58	$30.17
	6th Six Months	6	$29.56	$30.15	$30.75
	7th Six Months	7	$30.15	$30.75	$31.37
	8th Six Months	8	$30.79	$31.41	$32.04
3105	Tech Sr, Mapping	1	$31.00	$31.62	$32.25
	2nd Six Months	2	$31.57	$32.20	$32.84
	3rd Six Months	3	$32.34	$32.99	$33.65
	4th Six Months	4	$33.16	$33.82	$34.50
	5th Six Months	5	$33.96	$34.64	$35.33
	6th Six Months	6	$34.80	$35.50	$36.21
	7th Six Months	7	$35.65	$36.36	$37.09
3107	UDC I	1	$24.10	$24.58	$25.07
	2nd Six Months	2	$24.83	$25.33	$25.84
	3rd Six Months	3	$25.56	$26.07	$26.59
	4th Six Months	4	$26.36	$26.89	$27.43
	5th Six Months	5	$27.12	$27.66	$28.21
	6th Six Months	6	$27.93	$28.49	$29.06
	7th Six Months	7	$28.77	$29.35	$29.94
	8th Six Months	8	$29.66	$30.25	$30.86

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
3108	UDC II	1	$31.88	$32.52	$33.17
	2nd Six Months	2	$32.83	$33.49	$34.16
	3rd Six Months	3	$33.83	$34.51	$35.20
	4th Six Months	4	$34.83	$35.53	$36.24
3109	Coordinator Senior, Projects	1	$37.49	$38.24	$39.00
	2nd Six Months	2	$38.60	$39.37	$40.16
	3rd Six Months	3	$39.96	$40.76	$41.58
	4th Six Months	4	$41.36	$42.19	$43.03
	5th Six Months	5	$42.82	$43.68	$44.55
3146	Mechanical Specialist	1	$41.30	$42.13	$42.97
3178	Surveyor	1	$41.83	$42.67	$43.52
5144	Clerk Dispatcher	1	$36.16	$36.88	$37.62
5145	Mat Spec/LG/FSR	1	$31.16	$31.78	$32.42
	2nd Six Months	2	$32.32	$32.97	$33.63
	3rd Six Months	3	$33.66	$34.33	$35.02
5181	Meter Shop Dispatcher	1	$30.51	$31.12	$31.74
6054	Lead Comm Electrician	1	$47.07	$48.01	$48.97
6055	Lead Relay Electrician	1	$48.07	$49.03	$50.01
6056	Lead Substation Electrician	1	$45.79	$46.71	$47.64
6057	Lead Lineman	1	$46.25	$47.18	$48.12
6058	Lead Metering Electrician	1	$45.79	$46.71	$47.64
6062	Lead Underground Inspector	1	$39.16	$39.94	$40.74
6080	Lead Fleet Services Mechanic	1	$44.88	$45.78	$46.70

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
6089	Lead Surveyor	1	$46.02	$46.94	$47.88
6100	Line Clearance Inspector	1	$28.26	$28.83	$29.41
6104	Trainer Substation	1	$45.79	$46.71	$47.64
6105	Trainer Lines	1	$46.25	$47.18	$48.12
6107	Relay Electrician II	1	$43.71	$44.58	$45.47
6108	Comm Electrician II	1	$43.71	$44.58	$45.47
6110	Field Inspector	1	$42.89	$43.75	$44.63
6111	Circuit Inspector	1	$37.44	$38.19	$38.95
6112	Electrical Inspector	1	$44.13	$45.01	$45.91
6113	Line Troubleman	1	$44.14	$45.02	$45.92
6121	Substation Inspector	1	$43.71	$44.58	$45.47
6122	Substation Electrician	1	$41.63	$42.46	$43.31
6123	Journeyman Lineman	1	$42.03	$42.87	$43.73
6124	Journeyman Metering Electrician	1	$41.63	$42.46	$43.31
6130	Welder, Company Wide	1	$41.63	$42.46	$43.31
6136	Lines Groundman	1	$22.52	$22.97	$23.43
	2nd Six Months	2	$23.29	$23.76	$24.24
	3rd Six Months	3	$24.02	$24.50	$24.99
	4th Six Months	4	$24.95	$25.45	$25.96
	5th Six Months	5	$25.91	$26.43	$26.96
	6th Six Months	6	$26.91	$27.45	$28.00
	7th Six Months	7	$27.84	$28.40	$28.97

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
6150	Equipment Mechanic	1	$40.80	$41.62	$42.45
6151	Fleet Maintenance Technician	1	$29.33	$29.92	$30.52
	2nd Six Months	2	$30.20	$30.80	$31.42
	3rd Six Months	3	$31.11	$31.73	$32.36
	4th Six Months	4	$32.02	$32.66	$33.31
	5th Six Months	5	$32.85	$33.51	$34.18
6159	Warehouse Utility Tech T&D	1	$23.09	$23.55	$24.02
	2nd Six Months	2	$24.00	$24.48	$24.97
	3rd Six Months	3	$24.87	$25.37	$25.88
6166	Equipment Operator	1	$37.17	$37.91	$38.67
6172	Underground Inspector	1	$30.93	$31.55	$32.18
	2nd Six Months	2	$32.19	$32.83	$33.49
	3rd Six Months	3	$33.28	$33.95	$34.63
	4th Six Months	4	$34.46	$35.15	$35.85
	5th Six Months	5	$35.61	$36.32	$37.05
6173	Underground Line Locator	1	$22.73	$23.18	$23.64
	2nd Six Months	2	$23.85	$24.33	$24.82
	3rd Six Months	3	$25.07	$25.57	$26.08
	4th Six Months	4	$26.34	$26.87	$27.41
6177	High Boom Operator	1	$35.61	$36.32	$37.05
6180	Line Patrolman	1	$42.89	$43.75	$44.63
6182	Fleet Utility Tech	1	$25.77	$26.29	$26.82
	2nd Six Months	2	$26.67	$27.20	$27.74
	3rd Six Months	3	$27.52	$28.07	$28.63
	4th Six Months	4	$28.44	$29.01	$29.59
6183	Tool Repairer	1	$34.64	$35.33	$36.04
6184	Technician, Tool Compliance	1	$36.37	$37.10	$37.84

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
6185	Comm Groundman	1	$22.52	$22.97	$23.43
	2nd Six Months	2	$23.29	$23.76	$24.24
	3rd Six Months	3	$24.02	$24.50	$24.99
	4th Six Months	4	$24.95	$25.45	$25.96
	5th Six Months	5	$25.91	$26.43	$26.96
	6th Six Months	6	$26.91	$27.45	$28.00
	7th Six Months	7	$27.84	$28.40	$28.97
6156	Parts Specialist II, Utility Fleet	1	$31.68	$32.31	$32.96
	2nd six months	2	$32.62	$33.27	$33.94
	3rd six months	3	$33.58	$34.25	$34.94
	4th six months	4	$34.56	$35.25	$35.96
	5th six months	5	$35.60	$36.31	$37.04
6157	Parts Specialist I, Utility Fleet	1	$31.16	$31.78	$32.42
	2nd six months	2	$32.09	$32.73	$33.38
	3rd six months	3	$33.05	$33.71	$34.38
	4th six months	4	$34.04	$34.72	$35.41
	5th six months	5	$35.07	$35.77	$36.49
6187	Relief Line Troubleman	1	$44.98	$45.88	$46.80
6188	Clerk Driver	1	$30.55	$31.16	$31.78
	2nd Six Months	2	$31.73	$32.36	$33.01
	3rd Six Months	3	$32.94	$33.60	$34.27
	4th Six Months	4	$34.10	$34.78	$35.48
6189	Substation Groundman	1	$22.52	$22.97	$23.43
	2nd Six Months	2	$23.29	$23.76	$24.24
	3rd Six Months	3	$24.02	$24.50	$24.99
	4th Six Months	4	$24.95	$25.45	$25.96
	5th Six Months	5	$25.91	$26.43	$26.96
	6th Six Months	6	$26.91	$27.45	$28.00
	7th Six Months	7	$27.84	$28.40	$28.97
6190	Survey Instrument Tech	1	$30.93	$31.55	$32.18
	2nd Six Months	2	$32.19	$32.83	$33.49
	3rd Six Months	3	$33.28	$33.95	$34.63

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
	4th Six Months	4	$34.46	$35.15	$35.85
	5th Six Months	5	$35.61	$36.32	$37.05
6196	Metering UtilityTech-Mtr Svc	1	$16.87	$17.21	$17.55
	2nd Six Months	2	$17.79	$18.15	$18.51
	3rd Six Months	3	$18.65	$19.02	$19.40
	4th Six Months	4	$19.54	$19.93	$20.33
	5th Six Months	5	$20.44	$20.85	$21.27
	6th Six Months	6	$21.32	$21.75	$22.19
	7th Six Months	7	$22.22	$22.66	$23.11
6197	Communications Electrician I	1	$42.15	$42.99	$43.85
6198	Relay Electrician I	1	$42.79	$43.65	$44.52
6199	Master Lines Clearance Inspector	1	$29.68	$30.27	$30.88
7013	App Equip Mechanic	1	$32.23	$32.87	$33.53
	2nd Six Months	2	$33.12	$33.78	$34.46
	3rd Six Months	3	$34.04	$34.72	$35.41
	4th Six Months	4	$34.98	$35.68	$36.39
	5th Six Months	5	$36.01	$36.73	$37.46
	6th Six Months	6	$38.10	$38.86	$39.64
	7th Six Months	7	$40.80	$41.62	$42.45
7020	Apprentice Lineman	1	$23.11	$23.57	$24.04
	2nd Six Months	2	$25.21	$25.71	$26.22
	3rd Six Months	3	$27.33	$27.88	$28.44
	4th Six Months	4	$29.43	$30.02	$30.62
	5th Six Months	5	$31.53	$32.16	$32.80
	6th Six Months	6	$33.63	$34.30	$34.99
	7th Six Months	7	$35.73	$36.44	$37.17
	8th Six Months	8	$37.83	$38.59	$39.36
7021	App Substation Electrician	1	$30.90	$31.52	$32.15
	2nd Six Months	2	$32.16	$32.80	$33.46
	3rd Six Months	3	$33.24	$33.90	$34.58

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Collective Bargaining Agreement

09/24/2013-08/31/2017

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
	4th Six Months	4	$34.40	$35.09	$35.79
	5th Six Months	5	$35.57	$36.28	$37.01
	6th Six Months	6	$36.70	$37.43	$38.18
	7th Six Months	7	$37.85	$38.61	$39.38
	8th Six Months	8	$39.02	$39.80	$40.60
	9th Six Months	9	$41.63	$42.46	$43.31
7022	App Metering Electrician	1	$30.90	$31.52	$32.15
	2nd Six Months	2	$32.16	$32.80	$33.46
	3rd Six Months	3	$33.24	$33.90	$34.58
	4th Six Months	4	$34.40	$35.09	$35.79
	5th Six Months	5	$35.57	$36.28	$37.01
	6th Six Months	6	$36.70	$37.43	$38.18
	7th Six Months	7	$37.85	$38.61	$39.38
	8th Six Months	8	$39.02	$39.80	$40.60
	9th Six Months	9	$41.63	$42.46	$43.31
7024	App Comm Electrician	1	$30.90	$31.52	$32.15
	2nd Six Months	2	$32.16	$32.80	$33.46
	3rd Six Months	3	$33.24	$33.90	$34.58
	4th Six Months	4	$34.40	$35.09	$35.79
	5th Six Months	5	$35.57	$36.28	$37.01
	6th Six Months	6	$36.70	$37.43	$38.18
	7th Six Months	7	$37.85	$38.61	$39.38
	8th Six Months	8	$39.02	$39.80	$40.60
	9th Six Months	9	$41.63	$42.46	$43.31
7085	Meter Tester	1	$24.66	$25.15	$25.65
	2nd Six Months	2	$25.77	$26.29	$26.82
7093	Material Utility Technician	1	$23.09	$23.55	$24.02
	2nd Six Months	2	$24.00	$24.48	$24.97
	3rd Six Months	3	$24.87	$25.37	$25.88
7094	Maintenance Technician	1	$27.52	$28.07	$28.63
	2nd Six Months	2	$28.44	$29.01	$29.59
	3rd Six Months	3	$29.33	$29.92	$30.52
	4th Six Months	4	$30.20	$30.80	$31.42

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

TRANSMISSION & DISTRIBUTION - WAGES
Job Code	Job Title	Step	9/1/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
	5th Six Months	5	$31.11	$31.73	$32.36
	6th Six Months	6	$32.02	$32.66	$33.31
	7th Six Months	7	$32.85	$33.51	$34.18
7095	Chief, Crew	1	$37.63	$38.38	$39.15
	2nd Six Months	2	$38.49	$39.26	$40.05
	3rd Six Months	3	$39.28	$40.07	$40.87
	4th Six Months	4	$39.97	$40.77	$41.59
	5th Six Months	5	$40.82	$41.64	$42.47
7096	Maintenance Utility Tech	1	$16.87	$17.21	$17.55
	2nd Six Months	2	$17.79	$18.15	$18.51
	3rd Six Months	3	$18.65	$19.02	$19.40
	4th Six Months	4	$19.54	$19.93	$20.33
	5th Six Months	5	$20.44	$20.85	$21.27
	6th Six Months	6	$21.32	$21.75	$22.19
	7th Six Months	7	$22.22	$22.66	$23.11
7097	Facilitator, Design & Const	1	$44.13	$45.01	$45.91
7098	Tech, Multi-Trade I	1	$24.46	$24.95	$25.45
7099	Tech, Multi-Trade II	1	$28.97	$29.55	$30.14
7100	Tech, Multi-Trade III (Lead)	1	$35.40	$36.11	$36.83

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

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

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NV Energy - IBEW L396

Collective Bargaining Agreement

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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.

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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

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GENERATION

ARTICLE NO. 4

Union Activity

4.3 CONTRACTING WORKWORK:

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.

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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 SHIFTFIRST 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 SHIFTSECOND 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 SHIFTTHIRD 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.

SHIFTSHIFT 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.

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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 scheduled paid time off 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

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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, SHIFTSHIFT - as defined by Article 6.1 AND CLASSIFICATIONCLASSIFICATION), 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.

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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.

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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 - - - NN N N - - - -

Crew #4 - - - N N N - D D D - - - N N N N - - - - - - - D D D D

D = Day Shift6:00am (same day) - 6:00pm (same day)

N = Night Shift6:00pm (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 N NN - - - D D D

D = Day Shift6:00am (same day) - 6:00pm (same day)

N = Night Shift6:00pm (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

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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

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

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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.

September 24, 2013 through August 31, 2017 …………$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 and paid time off.

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

4^th 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 PTO 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 maybe in conjunction with the employee’s regularly scheduled days off, or any other day within that pay

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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.

PTO/Vacations: An employee’s PTO accrual shall be adjusted for all periods of leave of absence without pay as defined elsewhere in this Agreement by reducing the number of PTO 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 PTO available in the calendar year the adjustment is made, or when such adjustment exceeds the employee’s available PTO, the excess shall be applied against the employee’s next PTO accrual or the employee’s final paycheck, whichever occurs first.

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 time off 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 time off 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 accordance with Article 6.4, Overtime Pay. Callouts for coverage of unscheduled time off 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.

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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.

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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.

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Overtime: In computing overtime, intermission taken out for meals served other than on the job shall be deducted, and any holiday or scheduled paid time off 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 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 (5^th) 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 PTO 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

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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.

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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 scheduled paid time off 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.

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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 Eighty-eight (88) 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.

HolidaysHolidays:

New Year’s DayLabor Day

Martin Luther King DayVeterans Day

Memorial DayThanksgiving Day

4^th Of July Christmas Day

Note: It is understood that the holidays will be worked with the appropriate premium pay.

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Banked Holidays: The provision to bank holidays does not apply to individuals assigned to this schedule.

PTO in Conjunction with a holiday:

When PTO is used in conjunction with their observed holiday, the 36 for 40 employees will not be required to work the holiday.

Note: PTO hours will be charged against the Employees accrued hours as follows:

FRIDAY        =THIRTEEN (13) HOURS OF PTO

SATURDAY=THIRTEEN (13) HOURS OF PTO

SUNDAY=FOURTEEN (14) HOURS OF PTO

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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.

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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.

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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 the

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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 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.

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

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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

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.

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.

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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.

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GENERATION - WAGES
Job Code	Job Title	Step	9/24/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
5272	Gen Materials Representative	1	$29.60	$30.19	$30.79
6050	Electrical/Instrument Tech	1	$41.63	$42.46	$43.31
6059	Lead Electrical Tech	1	$45.79	$46.71	$47.64
6060	Lead Maintenance Tech	1	$45.79	$46.71	$47.64
6063	Lead Mechanical Tech/Mech	1	$45.79	$46.71	$47.64
6064	Lead Laboratory Tech	1	$41.59	$42.42	$43.27
6073	Lead Coal Yard Operator	1	$42.30	$43.15	$44.01
6161	Coal Yard Equipment Operator	1	$38.47	$39.24	$40.02
6094	Lead Control Operator	1	$45.79	$46.71	$47.64
6098	Material Utility Technician	1	$23.09	$23.55	$24.02
	2nd Six Months	2	$24.00	$24.48	$24.97
	3rd Six Months	3	$24.87	$25.37	$25.88
6102	Relief Control Operator	1	$43.14	$44.00	$44.88
6103	Trainer Power Delivery	1	$45.79	$46.71	$47.64
6118	Control Operator	1	$40.93	$41.75	$42.59
	2nd Six Months	2	$42.13	$42.97	$43.83
6129	Mechanical Tech/Welder	1	$41.63	$42.46	$43.31
6131	Mechanical Tech/Machinist	1	$41.63	$42.46	$43.31
6146	Mechanical Tech/Mechanic	1	$41.63	$42.46	$43.31
6160	Laboratory Tech	1	$33.92	$34.60	$35.29
	2nd Six Months	2	$35.16	$35.86	$36.58
	3rd Six Months	3	$36.45	$37.18	$37.92

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GENERATION - WAGES
Job Code	Job Title	Step	9/24/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
	4th Six Months	4	$37.81	$38.57	$39.34
6181	Maintenance Tech	1	$27.52	$28.07	$28.63
	2nd Six Months	2	$28.44	$29.01	$29.59
	3rd Six Months	3	$29.33	$29.92	$30.52
	4th Six Months	4	$30.20	$30.80	$31.42
	5th Six Months	5	$31.11	$31.73	$32.36
	6th Six Months	6	$32.02	$32.66	$33.31
	7th Six Months	7	$32.85	$33.51	$34.18
6192	Maintenance Utility Tech	1	$16.87	$17.21	$17.55
	2nd Six Months	2	$17.79	$18.15	$18.51
	3rd Six Months	3	$18.65	$19.02	$19.40
	4th Six Months	4	$19.54	$19.93	$20.33
	5th Six Months	5	$20.44	$20.85	$21.27
	6th Six Months	6	$21.32	$21.75	$22.19
	7th Six Months	7	$22.22	$22.66	$23.11
7001	Utility Operator	1	$16.87	$17.21	$17.55
	2nd Six Months	2	$17.79	$18.15	$18.51
	3rd Six Months	3	$18.65	$19.02	$19.40
	4th Six Months	4	$19.54	$19.93	$20.33
	5th Six Months	5	$20.44	$20.85	$21.27
	6th Six Months	6	$21.32	$21.75	$22.19
	7th Six Months	7	$22.22	$22.66	$23.11
7009	App Mechanical Tech/Welder	1	$30.90	$31.52	$32.15
	2nd Six Months	2	$32.16	$32.80	$33.46
	3rd Six Months	3	$33.24	$33.90	$34.58
	4th Six Months	4	$34.40	$35.09	$35.79
	5th Six Months	5	$35.57	$36.28	$37.01
	6th Six Months	6	$36.70	$37.43	$38.18
	7th Six Months	7	$37.85	$38.61	$39.38
	8th Six Months	8	$39.02	$39.80	$40.60
	9th Six Months	9	$41.63	$42.46	$43.31
7010	App Mechanical Tech/Machinist	1	$30.90	$31.52	$32.15
	2nd Six Months	2	$32.16	$32.80	$33.46

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GENERATION - WAGES
Job Code	Job Title	Step	9/24/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
	3rd Six Months	3	$33.24	$33.90	$34.58
	4th Six Months	4	$34.40	$35.09	$35.79
	5th Six Months	5	$35.57	$36.28	$37.01
	6th Six Months	6	$36.70	$37.43	$38.18
	7th Six Months	7	$37.85	$38.61	$39.38
	8th Six Months	8	$39.02	$39.80	$40.60
	9th Six Months	9	$41.63	$42.46	$43.31
7011	Apprentice Equipment Mechanic	1	$30.90	$31.52	$32.15
	2nd Six Months	2	$32.16	$32.80	$33.46
	3rd Six Months	3	$33.24	$33.90	$34.58
	4th Six Months	4	$34.40	$35.09	$35.79
	5th Six Months	5	$35.57	$36.28	$37.01
	6th Six Months	6	$36.70	$37.43	$38.18
	7th Six Months	7	$37.85	$38.61	$39.38
	8th Six Months	8	$39.02	$39.80	$40.60
	9th Six Months	9	$41.63	$42.46	$43.31
7012	App Electrical/Inst Technician	1	$30.90	$31.52	$32.15
	2nd Six Months	2	$32.16	$32.80	$33.46
	3rd Six Months	3	$33.24	$33.90	$34.58
	4th Six Months	4	$34.40	$35.09	$35.79
	5th Six Months	5	$35.57	$36.28	$37.01
	6th Six Months	6	$36.70	$37.43	$38.18
	7th Six Months	7	$37.85	$38.61	$39.38
	8th Six Months	8	$39.02	$39.80	$40.60
	9th Six Months	9	$41.63	$42.46	$43.31
7034	App Mechanical Tech/Mechanic	1	$30.90	$31.52	$32.15
	2nd Six Months	2	$32.16	$32.80	$33.46
	3rd Six Months	3	$33.24	$33.90	$34.58
	4th Six Months	4	$34.40	$35.09	$35.79
	5th Six Months	5	$35.57	$36.28	$37.01
	6th Six Months	6	$36.70	$37.43	$38.18
	7th Six Months	7	$37.85	$38.61	$39.38
	8th Six Months	8	$39.02	$39.80	$40.60
	9th Six Months	9	$41.63	$42.46	$43.31

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GENERATION - WAGES
Job Code	Job Title	Step	9/24/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
7046	Relief Assistant Control Operator	1	$38.81	$39.59	$40.38
7062	Assistant Control Operator	1	$36.74	$37.47	$38.22
	2nd Six Months	2	$37.81	$38.57	$39.34
7069	Relief Auxiliary Operator	1	$37.05	$37.79	$38.55
7076	Auxiliary Operator	1	$35.11	$35.81	$36.53
	2nd Six Months	2	$36.08	$36.80	$37.54
7077	Technical Specialist	1	$41.63	$42.46	$43.31

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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

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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

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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

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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.

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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 ResourcesBusiness Manager/Financial Secretary

Nevada Power CompanyIBEW Local 396

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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	9/24/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
6,065	Combined Cycle Operator	1	$43.38	$44.25	$45.14
	2nd Six Months	2	$44.67	$45.56	$46.47
6,066	Lead Combined Cycle Operator	1	$47.18	$48.12	$49.08
	2nd Six Months	2	$48.60	$49.57	$50.56
6,067	Production Technician	1	$43.38	$44.25	$45.14
	2nd Six Months	2	$44.67	$45.56	$46.47
6,068	Lead Production Technician	1	$47.18	$48.12	$49.08
	2nd Six Months	2	$48.60	$49.57	$50.56

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.

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

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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 and 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.

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.

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:

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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.

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.

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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

1.

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 may be 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

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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 provisions will apply into his regular work hours and thereby postpone starting time.

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.

September 24, 2013 through August 31, 2017: $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, and PTO..

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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.

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Articles 10, 11 and 12

Effective December 16, 2013, classifications within the Electric Systems Control group shall be covered under Article 10, 11 and 12 as defined in the Collective Bargaining Agreement.

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.

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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.

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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*	9/24/2013	1st Pay Period After 08/31/2014 2.0%	1st Pay Period After 08/31/2015 2.0%
Dispatch Assistant	4,016	Dispatcher Assistant Start	1 Year	$29.74	$30.33	$30.94
	4,017	Dispatcher Assistant	1 Year	$30.51	$31.12	$31.74
	4,018	Senior Dispatcher Assistant		$32.58	$33.23	$33.89
Distribution	4,019	Operator Start, Distribution	2 Year	$45.20	$46.10	$47.02
	4,020	Operator, Distribution	2 Year	$47.16	$48.10	$49.06
	4,021	Senior Operator, Distribution	Vacancy**	$49.85	$50.85	$51.87
Transmission	4,022	Operator, Sub-Transmission	Vacancy** NERC***	$50.57	$51.58	$52.61
	4,023	Operator, Transmission		$51.47	$52.50	$53.55
Training	4,006	Trainer, System Operator		$51.47	$52.50	$53.55
* 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

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Collective Bargaining Agreement

09/24/2013-08/31/2017

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.

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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 J. Kaleta/s/ Charlie Randall

For Company / Date                    For Union / Date

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

SUPPLY CHAIN

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.

OVERTIME:

Each reporting location will have its own overtime equalization list. Once supervision has exhausted the overtime equalization list for the specific reporting location, supervision may utilize the overtime equalization list for another reporting location, at management’s discretion, calling out the low person on the overtime equalization list.

FLEXIBILITY:

Any Material Specialist or Lead Material Specialist may be temporarily assigned to work at any Warehouse or Company location after initially reporting to their normal reporting location.

Example: A Material Specialist normally assigned to report to the Beltway could be assigned to make a delivery to Reid Gardner after first reporting to Beltway.

In addition, upon the agreement of a Material Specialist or Lead Material Specialist, the Company may assign an employee to report directly at a location other than their normal reporting location. Under such an assignment the employee would receive a flat fee as listed below:

	Assigned to Las Vegas Location	Assigned to Arrow Canyon Complex Location	Assigned to Reid Gardner Location
Normal Reporting Location in Las Vegas	$20.00 (if assigned to a different location)	$30.00	$40.00
Normal Reporting Location at Arrow Canyon Complex	$30.00	N/A	$20.00
Normal Reporting Location at Reid Gardner	$40.00	$20.00	N/A

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Example: A Material Specialist normally reporting at the Beltway could agree, upon the request of Company management, to report at the Arrow Canyon Complex for the day’s work. Other than the $30.00 flat fee, no mileage or drive time would be paid for such an assignment.

SUPPLY CHAIN

JOB CLASSIFICATION

(Alphabetical)

LEAD, MATERIAL SPECIALIST (6087)

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.

6087 Lead Material Specialist 1 $37.03 $37.77 $38.53

MATERIAL SPECIALIST (6088)

Performs any and all warehouse inventory functions in order to maintain and operate the warehouse. This includes but is not limited to manual and clerical duties in conjunction with receiving, storing, returns, transfers, picking, staging 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, creates, 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 must have and maintain a Class A Commercial Drivers’ License (CDL) in the State of Nevada. The Company will be 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. Operates forklifts and various material handling equipment. Supervises the orderly accumulation, and removal of scrap materials.

6088	Material Specialist	1	$31.16	$31.78	$32.42
	2nd Six Months	2	$32.32	$32.97	$33.63
	3rd Six Months	3	$34.18	$34.86	$35.56

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

A

ALTERNATIVE, 30, 49, 57, 65, 110

ALTERNATIVE SHIFTS, 15, 71, 80, 114, 119, 122, 143

AMENDMENT, 4, 51, 54

APPLICATION REFERRAL, 10

APPRENTICE, 51, 85

ASSIGNMENT TO AN ESTABLISHED SCHEDULE, 19

B

BANKED HOLIDAYS, 29, 116, 124

BENEFIT, 3, 11, 12, 13, 33, 35, 36, 39, 41

BENEFITS, 8, 9, 10, 11, 12, 24, 29, 33, 34,35, 36, 37, 38, 39, 40, 41, 42, 43, 46, 48, 50, 57, 58, 50, 60, 61, 63, 143

BOARD AND LODGING, 20

BREAK PERIOD, 15, 81, 111, 115, 122

bridged time for re-hired employees, 24, 44

BULLETIN BOARDS, 7

BUSINESS MANAGEMENT, 6

C

CALL-OUTS, 16, 66, 81, 82, 111, 112, 113, 115, 122, 144

CHANGE, 4, 9, 17, 18, 22, 43, 49, 68, 120, 123, 135, 143

CLASSIFICATION, 3, 9, 10, 11, 15, 23, 24, 34, 35, 49, 52, 53, 57, 58, 63, 65, 68, 69, 86, 117, 123, 126, 136, 150, 151, 156

CLASSIFICATIONS, 4, 8, 10, 16, 49, 65, 78, 82, 07, 112, 137, 138, 140, 143, 149, 150, 151, 155

COMPANY HOLIDAYS, 29, 107

CONSIDERATIONS, 32, 82, 113

CONSTRUCTION, 53, 78, 79, 85, 109, 138, 155

CONTINUITY OF SERVICE, 3, 54

CONTRACTING, 7, 11, 62, 78, 109, 138, 139, 142, 143, 155

CREW, 51, 53, 83, 85, 106, 125

D

Days Off, 17, 19, 21, 29, 32, 47, 52, 63, 65, 71, 80, 81, 110, 111, 116, 122, 144

DISABILITY, 4, 29, 32, 33, 34, 35, 36, 37, 43, 57, 150

DISCIPLINE, 6, 15, 22, 47, 49, 53, 83, 142

Double Time,16, 29, 32, 66, 71, 81, 111, 115, 117, 120, 122, 144

E

EARLY RELEASE, 21

ELIGIBILITY, 12, 33, 36, 39, 41, 42, 57, 63, 70

ELIGIBLE EMPLOYEES, 13, 29, 37, 38, 40, 42

EMERGENCY, 4, 16, 19, 27, 49, 64, 85, 112, 115, 116, 129, 135, 144

EMERGENCY OR TEMPORARY SCHEDULES, 19, 20, 80, 110, 119

EMPLOYEE STATUS DESIGNATION, 8

ENERGIZED PANELS, 28

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EQUALIZATION, 16, 66, 82, 112, 135, 155

EQUALIZING ASSIGNMENTS, 20

ESTABLISHING PERMANENT SCHEDULES, 17, 120

EXCEPTIONS, 16, 18, 112

EXCLUSIONS, 43

F

FACILITIES, 26, 27, 28, 49, 53, 78, 79, 136

FAMILY, 31, 38, 39, 47, 48, 69, 150

FIRST SHIFT, 17, 65, 71, 80, 110, 119

FROZEN SICK LEAVE, 32, 33, 34, 36, 44, 48

H

HEADQUARTERS, 12, 20, 23, 68, 81, 111

HEALTH AND SAFETY, 28

HEARING PROCEDURES, 23, 142

Holidays, 16, 17, 29, 30, 57, 71, 107, 112, 116, 120, 123, 124, 144, 145

I

INCLEMENT WEATHER, 27

INJURIES, 35, 43

INTERVIEW, 23, 70, 142

INTRA-DEPARTMENTAL WORK LOCATION CHANGE, 22, 23, 24

INTRODUCTION, 3, 31

J

Job Code, 76, 98, 131, 140, 151

JURY DUTY, 47

L

LABOR, 3, 16, 19, 24, 27, 49, 50, 66, 70, 82, 112

LEAD, 52, 68, 85, 106

LEAST SENIOR QUALIFIED, 17, 19, 123

LEAVES, 29, 46

LICENSE, 53, 67

LIGHT DUTY, 33

Lunch Periods, 15, 71, 119, 122

M

Meal, 20, 21, 64, 65, 71, 81, 111, 114, 116, 120, 122, 123, 143, 144

MEAL PERIODS, 17, 19, 81, 111, 115

MEAL RATES, 21

MEAL TIMES, 20, 116, 120, 123, 144

MEDICAL, 8, 11, 12, 30, 34, 36, 37, 39, 41, 43, 46, 48, 59, 60, 61, 63, 69

Mileage, 20, 67, 156

MILEAGE ALLOWANCE, 20

MOVING EXPENSES, 23

MUTUAL INTERESTS, 18, 27

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NV Energy - IBEW L396

Collective Bargaining Agreement

09/24/2013-08/31/2017

N

NEW EMPLOYEES, 5

NO QUALIFIED BIDDERS, 23, 143

NON-DISCRIMINATION, 3, 4

NOTIFICATION, 10, 11, 12, 17, 18, 19, 21, 25, 26, 50, 52, 57, 66, 83, 106, 113, 120, 123

O

OFFICE, 5, 22, 28, 46, 49, 66, 67, 68

OUT OF TOWN WORK, 20

P

PART-TIME, 9, 10, 11, 15, 41, 63, 65, 69, 122

PAY DAYS, 16, 23, 112

PAY PROVISIONS, 16, 23, 112

PICKET, 4

POLICIES, 16, 27, 32, 50, 66, 82, 112

POSTING, 7, 22, 23, 70

POSTING REQUIREMENT, 22

POSTINGS, 22

Premium, 11, 17, 18, 19, 20, 29, 43, 46, 63, 65, 66, 80, 81, 82, 110, 111, 113, 116, 119, 120, 123, 125, 144

PROBATIONARY, 8, 9, 10, 11, 24, 29, 31, 43, 68, 70

PROVISIONS, 3, 4, 6, 10, 16, 19, 21, 22, 23, 25, 27, 30, 31, 33, 34, 35,39, 41, 42, 46, 49, 50, 52, 54, 57, 68, 69, 82, 107, 114, 115, 119, 122, 143, 144, 150, 151

PTO, 31, 32, 34, 36, 57, 71, 116, 117, 120, 124, 144, 145

R

RAIN GEAR, 28

RATE OF PAY AND ROTATION, 20

RATES, 3, 15, 23, 37, 40, 42, 43, 46, 64, 65, 66, 70, 80, 83, 107, 110, 112, 114, 115, 119, 122, 143, 144, 151, 156

RECALL, 10, 11, 46, 57, 58, 78, 109, 155

Recall Rights, 11, 78, 109, 155

RECOVERING OVERPAYMENTS, 16, 112

RED CIRCLE/GRANDFATHER, 15

REGULAR EMPLOYEE, 8, 9, 10, 11, 24, 29, 31, 34, 46, 47, 63, 69, 116

REPORTING DEFICIENCIES, 27

REPORTING LOCATION, 68, 155

Rest Time, 16, 17, 32, 71, 82, 112, 116, 120, 123, 144

RETURN TO ORIGINAL OR OTHER SCHEDULE, 18

RETURN TO ORIGINAL SCHEDULE, 20

RIGHT OF ASSIGNMENT, 18, 19

RULE VIOLATIONS, 27

S

SAFETY, 27, 28, 34, 38, 45, 49, 52, 85, 125

SAFETY COMMITTEE, 27

SAFETY INVESTIGATIONS, 27

SAFETY MEETINGS, 27

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NV Energy - IBEW L396

Collective Bargaining Agreement

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SCHEDULE PREFERENCE AGREEMENTS, 19

SCHEDULING, 32, 55, 69, 79, 83, 113, 114, 117, 123, 144, 145

SECOND SHIFT, 17, 65, 71, 110, 119, 141

SELECTION CRITERIA, 23, 24, 142

SEMI-ANNUAL INSPECTIONS, 27

SENIORITY, 8, 9, 10, 11, 12, 17, 22, 23, 24, 32, 34, 36, 46, 57, 58, 63, 68, 69, 123, 135, 142

SEVEN DAY COVERAGE, 15, 80, 110

SEVEN-DAY Coverage Employees, 16

SEVERANCE, 11, 12, 13, 14, 78, 109, 136, 155

SHIFT DIFFERENTIAL, 17, 18, 19, 20, 64, 65, 80, 110, 116, 120, 135, 144

SICK, 19, 31, 32, 33, 34, 36, 43, 48, 115

STAFFING OF SCHEDULES, 17

STRAIGHT TIME PAY, 15, 16, 71, 82, 112, 116, 117, 120, 144

SUBPOENA, 47

T

TEMPORARY, 8, 9, 10, 11, 19, 20, 23, 33, 41, 43, 46, 47, 52, 53, 57, 58, 68, 69, 80, 85, 110, 116, 118, 119, 142,

TEMPORARY EMPLOYEES, 8, 29, 39, 41, 43, 47, 116

THIRD SHIFT, 17, 66, 71, 80, 110, 119

TIME OFF, 7, 10, 16, 17, 31, 44, 46, 47, 48, 65, 66, 69, 71, 81, 82, 111, 112, 116, 117, 120, 122, 123,

144, 146

Time And A Half, 64, 66, 71, 81, 107, 111, 120, 122

TOOLS, 52, 85, 125

Training, 9, 10, 12, 18, 23, 34, 35, 46, 47, 51, 53, 64, 69, 73, 74, 75, 85, 123, 137, 140

TRAINING EXCEPTIONS, 18

TRAVEL TIME, 18, 82, 83, 112, 113, 115, 144

TRAVEL TIME FOR OUT OF TOWN TRAINING, 18

TRIAL PERIOD, 22, 24, 142

U

UNION BUSINESS, 5, 7, 9, 23, 34

UNION DUES, 5

UNION LEADERSHIP ACCESS, 7

UNION STEWARD BUSINESS, 7

V

VACATION,16, 31, 32, 52, 53, 69, 112, 117

VEHICLE, 53, 67

VOLUNTEERS, 12,17, 19, 50, 57, 58, 69, 123, 135, 137

W

WAGES, 3, 5, 15, 16, 49, 50, 54, 57, 62, 78, 98, 109, 112, 131, 138, 140, 143, 149, 155

WELDING, 52

Work Week, 19, 47, 65, 71, 80, 107, 110, 114, 117, 119, 120, 122

Workday, 16, 18, 29, 63, 66, 71, 81, 107, 111, 112, 114, 115, 117, 119, 120, 122, 123, 143, 144

WORKED HOLIDAYS, 29

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EX-12.1

EXHIBIT 12.1
NV ENERGY, INC.
RATIOS OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
		Nine Months Ended
		September 30,						Year Ended December 31,
		2013			2012			2012			2011			2010			2009			2008
EARNINGS AS DEFINED:
Net Income		$	271,942		$	304,782		$	321,946		$	163,432		$	226,984		$	182,936		$	208,887
Income tax expense		148,430			165,466			166,592			86,915			113,764			75,451			95,354
Fixed Charges		231,614			236,059			312,801			343,719			363,773			360,896			335,868
Capitalized Interest (allowance for
borrowed funds used during construction)		(5,770		)	(5,479		)	(7,493		)	(8,718		)	(23,355		)	(20,229		)	(29,527		)
Total		$	646,216		$	700,828		$	793,846		$	585,348		$	681,166		$	599,054		$	610,582
FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)		$	231,614		$	236,059		$	312,801		$	343,719		$	363,773		$	360,896		$	335,868
Total		$	231,614		$	236,059		$	312,801		$	343,719		$	363,773		$	360,896		$	335,868
RATIO OF EARNINGS TO FIXED
CHARGES		2.79			2.97			2.54			1.70			1.87			1.66			1.82
(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” represents 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)
		Nine Months Ended
		September 30,						Year Ended December 31,
		2013			2012			2012			2011			2010			2009			2008
EARNINGS AS DEFINED:
Net income		$	228,552		$	256,151		$	257,738		$	132,586		$	185,943		$	134,284		$	151,431
Income tax expense		124,730			137,328			138,113			70,737			91,757			61,652			71,382
Fixed Charges		164,029			166,129			220,470			233,788			240,830			247,290			210,067
Capitalized Interest (allowance for
borrowed funds used during construction)		(4,763		)	(4,021		)	(5,437		)	(6,770		)	(21,443		)	(17,184		)	(20,063		)
Total		$	512,548		$	555,587		$	610,884		$	430,341		$	497,087		$	426,042		$	412,817
FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)		$	164,029		$	166,129		$	220,470		$	233,788		$	240,830		$	247,290		$	210,067
Total		$	164,029		$	166,129		$	220,470		$	233,788		$	240,830		$	247,290		$	210,067
RATIO OF EARNINGS TO FIXED
CHARGES		3.12			3.34			2.77			1.84			2.06			1.72			1.97
(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” represents 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)
		Nine Months Ended
		September 30,						Year Ended December 31,
		2013			2012			2012			2011			2010			2009			2008
EARNINGS AS DEFINED:
Net Income		$	61,931		$	65,750		$	84,354		$	59,886		$	72,375		$	73,085		$	90,582
Income tax expense		30,347			33,596			40,221			31,197			40,404			31,225			37,603
Fixed Charges		47,914			50,067			65,838			70,418			72,815			74,955			84,478
Capitalized Interest (allowance for
borrowed funds used during construction)		(1,007		)	(1,458		)	(2,056		)	(1,948		)	(1,912		)	(3,044		)	(9,464		)
Total		$	139,185		$	147,955		$	188,357		$	159,553		$	183,682		$	176,221		$	203,199
FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)		$	47,914		$	50,067		$	65,838		$	70,418		$	72,815		$	74,955		$	84,478
Total		$	47,914		$	50,067		$	65,838		$	70,418		$	72,815		$	74,955		$	84,478
RATIO OF EARNINGS TO FIXED
CHARGES		2.90			2.96			2.86			2.27			2.52			2.35			2.41
(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” represents the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed attributable to interest.

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 quarterly report on Form 10-Q for the quarter ended September 30, 2013 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.

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.

November 6, 2013

/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 quarterly report on Form 10-Q for the quarter ended September 30, 2013 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.

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.

November 6, 2013

/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 quarterly report on Form 10-Q for the quarter ended September 30, 2013 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.

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.

November 6, 2013

/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, E. Kevin Bethel, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended September 30, 2013 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.

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.

November 6, 2013

/s/ E. Kevin Bethel   

E. Kevin Bethel

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, E. Kevin Bethel, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended September 30, 2013 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.

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.

November 6, 2013

/s/ E. Kevin Bethel

E. Kevin Behel  

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, E. Kevin Bethel, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended September 30, 2013 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.

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.

November 6, 2013

/s/ E. Kevin Bethel

E. Kevin Bethel  

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-Q for the quarter ended September 30, 2013 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)

November 6, 2013

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-Q for the quarter ended September 30, 2013 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)

November 6, 2013

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 (NV ENERGY)

(“Registrant”)

In connection with this report of Sierra Pacific Power Company (dba NV Energy) on Form 10-Q for the quarter ended September 30, 2013 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

Sierra Pacific Power Company (dba NV Energy)

(Principal Executive Officer)

November 6, 2013

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-Q for the quarter ended September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, E. Kevin Bethel, 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/ E. Kevin Bethel

E. Kevin Bethel 

Chief Financial Officer

NV Energy, Inc.

(Principal Financial Officer)

November 6, 2013

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-Q for the quarter ended September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, E. Kevin Bethel, 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/ E. Kevin Bethel

E. Kevin Bethel 

Chief Financial Officer

Nevada Power Company (dba NV Energy)

(Principal Financial Officer)

November 6, 2013

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-Q for the quarter ended September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, E. Kevin Bethel, 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/ E. Kevin Bethel

E. Kevin Bethel 

Chief Financial Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Financial Officer)

November 6, 2013

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.

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EARNINGS PER SHARE (NVE)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE (NVE)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan. 

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Basic EPS
Numerator ($000)
Net Income	$	187,234	$	223,170	$	271,942	$	304,782
Denominator
Weighted average number of common shares outstanding	235,578,310		235,961,402		235,421,933		235,986,874
Per Share Amounts
Net Income per share - basic	$	0.79	$	0.95	$	1.16	$	1.29
Diluted EPS
Numerator ($000)
Net Income	$	187,234	$	223,170	$	271,942	$	304,782
Denominator(1)
Weighted average number of shares outstanding before dilution	235,578,310		235,961,402		235,421,933		235,986,874
Stock options	61,927		39,256		46,537		37,592
Non-Employee Director stock plan	190,705		166,829		185,337		160,257
Employee stock purchase plan	4,149		6,742		5,831		6,785
Restricted Shares	412,000		584,750		487,667		533,750
Performance Shares	1,358,423		1,362,753		1,191,734		1,125,272
Diluted Weighted Average Number of Shares	237,605,514		238,121,732		237,339,039		237,850,530
Per Share Amounts
Net income per share - diluted	$	0.79	$	0.94	$	1.15	$	1.28

(1) The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending September 30, 2012.  If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets:
Cash and cash equivalents	$ 373,026	$ 298,271
Accounts receivable less allowance for uncollectible accounts	483,178	373,099
Materials, supplies and fuel, at average cost	121,699	138,337
Deferred energy costs current	82,235	0
Deferred income taxes	120,186	60,592
Other current assets	49,041	40,750
Total Current Assets	1,229,365	911,049
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant in service	12,195,312	12,031,053
Construction work-in-progress	821,430	708,109
Total	13,016,742	12,739,162
Less accumulated provision for depreciation	3,526,824	3,313,188
Public Utilities, Property, Plant and Equipment, Net	9,489,918	9,425,974
Investments and other property, net	65,354	56,660
Other Assets, Noncurrent [Abstract]
Deferred Energy Costs Non Current	85,055	87,072
Regulatory assets	1,048,204	1,132,768
Regulatory asset for pension plans	270,565	281,195
Other Assets, Noncurrent	76,705	89,418
Total Deferred Charges and Other Assets	1,480,529	1,590,453
Assets	12,265,166	11,984,136
Current Liabilities:
Current maturities of long-term debt	129,457	356,283
Accounts Payable	316,681	332,245
Accrued expenses	104,781	127,693
Deferred energy	0	136,865
Other current liabilities	88,299	66,221
Total Current Liabilities	639,218	1,019,307
Long-term debt	4,791,809	4,669,798
Commitments and Contingencies
Deferred Credits and Other Liabilities:
Deferred income taxes	1,680,896	1,470,973
Deferred investment tax credit	11,623	13,538
Accrued retirement benefits	144,696	162,260
Regulatory liabilities	631,368	550,687
Other deferred credits and liabilities	656,963	540,202
Total Deferred Credits and Other Liabilities	3,125,546	2,737,660
Shareholders' Equity
Common stock	236,000	236,000
Treasury stock, at cost	(7,898)	(16,804)
Other paid-in capital	2,716,311	2,712,943
Retained earnings	772,995	635,303
Accumulated other comprehensive loss	(8,815)	(10,071)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,708,593	3,557,371
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	12,265,166	11,984,136
Nevada Power Company
Current Assets:
Cash and cash equivalents	255,236	201,202
Accounts receivable less allowance for uncollectible accounts	367,365	248,501
Materials, supplies and fuel, at average cost	70,929	77,675
Deferred energy costs current	68,391	0
Deferred income taxes	80,062	48,590
Other current assets	35,984	28,763
Total Current Assets	877,967	604,731
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant in service	8,459,208	8,363,566
Construction work-in-progress	695,749	567,941
Total	9,154,957	8,931,507
Less accumulated provision for depreciation	2,203,320	2,035,322
Public Utilities, Property, Plant and Equipment, Net	6,951,637	6,896,185
Investments and other property, net	51,114	49,808
Other Assets, Noncurrent [Abstract]
Deferred Energy Costs Non Current	84,041	87,072
Regulatory assets	746,286	804,013
Regulatory asset for pension plans	131,628	136,682
Other Assets, Noncurrent	58,097	62,654
Total Deferred Charges and Other Assets	1,020,052	1,090,421
Assets	8,900,770	8,641,145
Current Liabilities:
Current maturities of long-term debt	129,186	106,048
Accounts Payable	202,915	201,193
Accounts Payable, Related Parties, Current	43,800	42,036
Accrued expenses	63,465	86,433
Deferred energy	0	86,102
Other current liabilities	69,479	52,567
Total Current Liabilities	508,845	574,379
Long-term debt	3,103,980	3,230,808
Commitments and Contingencies
Deferred Credits and Other Liabilities:
Deferred income taxes	1,257,818	1,101,804
Deferred investment tax credit	3,857	4,688
Accrued retirement benefits	52,429	49,381
Regulatory liabilities	376,136	323,400
Other deferred credits and liabilities	551,545	434,367
Total Deferred Credits and Other Liabilities	2,241,785	1,913,640
Shareholders' Equity
Common stock	1	1
Other paid-in capital	2,308,211	2,308,211
Retained earnings	742,164	618,612
Accumulated other comprehensive loss	(4,216)	(4,506)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,046,160	2,922,318
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	8,900,770	8,641,145
Sierra Pacific Power Company
Current Assets:
Cash and cash equivalents	84,128	60,786
Accounts receivable less allowance for uncollectible accounts	115,765	124,464
Materials, supplies and fuel, at average cost	50,770	60,662
Deferred energy costs current	13,844	0
Intercompany income taxes receivable	10,351	10,351
Deferred income taxes	49,748	21,589
Other current assets	12,566	11,633
Total Current Assets	337,172	289,485
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant in service	3,736,104	3,667,487
Construction work-in-progress	125,681	140,168
Total	3,861,785	3,807,655
Less accumulated provision for depreciation	1,323,504	1,277,866
Public Utilities, Property, Plant and Equipment, Net	2,538,281	2,529,789
Investments and other property, net	7,126	6,499
Other Assets, Noncurrent [Abstract]
Deferred Energy Costs Non Current	1,014	0
Regulatory assets	301,918	328,755
Regulatory asset for pension plans	135,257	140,268
Other Assets, Noncurrent	13,524	21,477
Total Deferred Charges and Other Assets	451,713	490,500
Assets	3,334,292	3,316,273
Current Liabilities:
Current maturities of long-term debt	271	250,235
Accounts Payable	84,277	106,415
Accounts Payable, Related Parties, Current	21,543	21,534
Accrued expenses	29,909	32,936
Deferred energy	0	50,763
Other current liabilities	18,821	13,655
Total Current Liabilities	154,821	475,538
Long-term debt	1,177,829	928,990
Commitments and Contingencies
Deferred Credits and Other Liabilities:
Deferred income taxes	525,694	465,508
Deferred investment tax credit	7,766	8,850
Accrued retirement benefits	75,133	98,676
Regulatory liabilities	255,232	227,287
Other deferred credits and liabilities	76,974	72,688
Total Deferred Credits and Other Liabilities	940,799	873,009
Shareholders' Equity
Common stock	4	4
Other paid-in capital	1,111,266	1,111,266
Retained earnings	(49,055)	(70,986)
Accumulated other comprehensive loss	(1,372)	(1,548)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,060,843	1,038,736
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 3,334,292	$ 3,316,273

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MERGER RELATED ACTIVITIES

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

MERGER RELATED ACTIVITIES

MERGER-RELATED ACTIVITIES

MidAmerican Merger

On May 29, 2013, NVE entered into the MidAmerican Merger Agreement.  The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation.  Once merged, NVE will become an indirect wholly owned subsidiary of MEHC.  The closing is expected to occur in late 2013 or the first quarter of 2014.

Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest and subject to applicable withholding taxes. 

The MidAmerican Merger Agreement has been approved by the BOD of both NVE and MEHC, but the consummation of the MidAmerican Merger is subject to the satisfaction or waiver of specified closing conditions, including:

• the approval of the MidAmerican Merger Agreement by the holders of a majority of the outstanding shares of NVE common stock. On September 25, 2013, NVE’s stockholders approved the MidAmerican Merger Agreement. Consequently, this closing condition has been satisfied;

• the receipt of regulatory approvals and other consents required to consummate the MidAmerican Merger, including, among others, approvals from the PUCN and the FERC on terms and conditions specified in the MidAmerican Merger Agreement (in July 2013, filings were made with the PUCN and FERC. See Note 4, Regulatory Actions, for further details of these filings);

• the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. On July 22, 2013, NVE was advised that the Department of Justice and the U.S. Federal Trade Commission had terminated the applicable waiting period under the Hart-Scott-Rodino Act.  Consequently, the closing condition with respect to the Hart-Scott-Rodino Act has been satisfied;

• the absence of the occurrence of a company material adverse effect (as defined in the MidAmerican Merger Agreement) after the date of the MidAmerican Merger Agreement; and

• other customary closing conditions.

The MidAmerican Merger Agreement contains customary representations, warranties and covenants for both NVE and MEHC. These covenants include an obligation for us, subject to certain exceptions, to conduct our business in a manner substantially consistent with our current practice. In addition, the covenants contain several restrictions that apply unless MEHC’s consent is received, including limitations on making certain business acquisitions, limitations on our total capital spending, limitations on the extent to which we may obtain financing through long-term debt or equity issuances and limitations on increasing our common stock dividend payout. 

The MidAmerican Merger Agreement contains certain termination rights and fees for both NVE and MEHC. In the event of termination of the MidAmerican Merger under certain circumstances, NVE may be obligated to pay MEHC a termination fee of up to $169.7 million.

During the three and nine month periods ending September 30, 2013, NVE incurred $7.9 million (pre-tax) and $21.4 million (pre-tax) of merger-related fees and stock compensation costs related to the MidAmerican Merger which have been expensed and presented on the Statement of Comprehensive Income as Merger-Related Costs.  Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation, upon announcement of the MidAmerican Merger.  NVE expects to incur additional merger fees relating to the MidAmerican Merger upon consummation of the MidAmerican Merger.

As a result of the pending MidAmerican Merger, NVE, its directors, Silver Merger Sub, Inc. and, in some cases, MEHC, have been named as defendants in certain lawsuits brought by alleged NVE shareholders seeking, among other things, to enjoin the proposed MidAmerican Merger; see Note 8, Commitments and Contingencies for further details.  In addition, NVE has ceased the repurchase of any common stock for NVE stock compensation plans; see Note 10, Common Stock and Other Paid-In Capital. 

The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination.  The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities.  As a result, NVE, NPC and SPPC will be required to offer to purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing.  At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers.  The average interest rate under these debt securities is approximately 6.25%, 6.42% and 5.51% for NVE, NPC and SPPC, respectively.  To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities’ revolving credit facilities or the issuance of long-term debt. Furthermore, NVE and the Utilities were required to obtain consents from lenders under the terms of the Utilities’ revolving credit facilities and NVE’s Term Loan before consummating the MidAmerican Merger. In November 2013, NVE amended its Term Loan and NPC and SPPC amended their revolving credit facilities, in each case to permit the MidAmerican Merger.

One Company Merger between NPC and SPPC

As detailed further in Note 4, Regulatory Actions, NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC.   The One Company Merger is subject to approval by the PUCN and FERC.

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EARNINGS PER SHARE (NVE) (Tables)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Basic EPS
Numerator ($000)
Net Income	$	187,234	$	223,170	$	271,942	$	304,782
Denominator
Weighted average number of common shares outstanding	235,578,310		235,961,402		235,421,933		235,986,874
Per Share Amounts
Net Income per share - basic	$	0.79	$	0.95	$	1.16	$	1.29
Diluted EPS
Numerator ($000)
Net Income	$	187,234	$	223,170	$	271,942	$	304,782
Denominator(1)
Weighted average number of shares outstanding before dilution	235,578,310		235,961,402		235,421,933		235,986,874
Stock options	61,927		39,256		46,537		37,592
Non-Employee Director stock plan	190,705		166,829		185,337		160,257
Employee stock purchase plan	4,149		6,742		5,831		6,785
Restricted Shares	412,000		584,750		487,667		533,750
Performance Shares	1,358,423		1,362,753		1,191,734		1,125,272
Diluted Weighted Average Number of Shares	237,605,514		238,121,732		237,339,039		237,850,530
Per Share Amounts
Net income per share - diluted	$	0.79	$	0.94	$	1.15	$	1.28

(1) The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending September 30, 2012.  If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

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COMMON STOCK AND OTHER PAID-IN CAPITAL

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

COMMON STOCK AND OTHER PAID-IN CAPITAL

COMMON STOCK AND OTHER PAID-IN CAPITAL

Dividends

The following dividend declarations were made by the BOD of NVE:

Declaration Date	Amount	Payable Date	Shareholders of Record Date
February 7, 2013	$0.19	March 20, 2013	March 5, 2013
May 8, 2013	$0.19	June 19, 2013	June 4, 2013
August 1, 2013	$0.19	September 18, 2013	September 3, 2013
November 6, 2013	$0.19	December 18, 2013	December 3, 2013

On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively. For the nine months ended September 30, 2013, NPC and SPPC paid dividends to NVE of $105.0 million and $40.0 million, respectively.

Treasury Stock

NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program.  All shares repurchased are held as treasury stock and may be reissued upon exercise or settlement of the stock compensation award.  Treasury stock is accounted for using the cost method. During the nine months ended September 30, 2013, NVE repurchased 325,178 shares of common stock for approximately $6.3 million.  During the nine months ended September 30, 2013, NVE re-issued 827,097 treasury shares to satisfy employee benefit plans.  In May 2013, NVE ceased the repurchase of common stock as a result of the proposed MidAmerican Merger.

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EARNINGS PER SHARE (NVE) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Numerator
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 187,234		$ 223,170		$ 271,942		$ 304,782
Denominator
Weighted Average Shares of Common Stock Outstanding - basic	235,578,310		235,961,402		235,421,933		235,986,874
Per Share Amounts
Net income per share - basic	$ 0.79		$ 0.95		$ 1.16		$ 1.29
Numerator
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 187,234		$ 223,170		$ 271,942		$ 304,782
Denominator
Weighted Average Number of Shares Outstanding, Basic	235,578,310		235,961,402		235,421,933		235,986,874
Stock options (in shares)	61,927		39,256		46,537		37,592
Non-Employee Director stock plan (in shares)	190,705		166,829		185,337		160,257
Employee stock purchase plan (in shares)	4,149		6,742		5,831		6,785
Restricted Shares (in shares)	412,000		584,750		487,667		533,750
Performance Shares (in shares)	1,358,423		1,362,753		1,191,734		1,125,272
Weighted Average Number of Shares Outstanding, Diluted	237,605,514	[1]	238,121,732	[1]	237,339,039	[1]	237,850,530	[1]
Per Share Amounts
Net income per share - diluted	$ 0.79		$ 0.94		$ 1.15		$ 1.28
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	327,503				329,382

[1] The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending September 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

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SEGMENT INFORMATION (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Segment Reporting Information [Line Items]
Operating Revenues	$ 1,013,151	$ 1,026,488	$ 2,329,011	$ 2,378,606
Energy Costs:
Fuel for power generation	217,954	171,316	554,181	400,936
Purchased power	205,970	205,686	498,141	486,894
Gas purchased for resale	7,383	5,382	62,277	46,491
Deferred energy	(55,270)	(29,036)	(221,022)	(30,285)
Energy efficiency program costs	16,042	32,584	38,486	76,609
Regulatory Disallowances	17,335	0	17,335	0
Total Costs	409,414	385,932	949,398	980,645
Gross Margin	603,737	640,556	1,379,613	1,397,961
Merger related costs	7,857	0	21,409	0
Other Cost and Expense, Operating	106,068	100,108	317,538	307,080
Utilities Operating Expense, Maintenance	17,176	19,014	66,128	76,190
Depreciation, Depletion and Amortization, Nonproduction	96,801	94,512	291,687	281,690
Taxes, Other	14,214	15,682	46,536	44,457
OPERATING INCOME	361,621	411,240	636,315	688,544
Unallocated Amount to Segment
Segment Reporting Information [Line Items]
Operating Revenues	3	4	10	12
Energy Costs:
Total Costs	0	0	0	0
Gross Margin	3	4	10	12
Merger related costs	229		1,394
Other Cost and Expense, Operating	830	608	2,747	2,382
Taxes, Other	57	45	318	282
OPERATING INCOME	(1,113)	(649)	(4,449)	(2,652)
NPC Electric
Segment Reporting Information [Line Items]
Operating Revenues	786,142	802,334	1,695,129	1,751,165
Energy Costs:
Fuel for power generation	163,127	123,992	412,904	285,799
Purchased power	172,582	171,687	383,386	388,494
Deferred energy	(45,381)	(22,685)	(154,484)	(15,461)
Energy efficiency program costs	13,998	28,492	32,807	65,466
Regulatory Disallowances	11,866		11,866
Total Costs	316,192	301,486	686,479	724,298
Gross Margin	469,950	500,848	1,008,650	1,026,867
Merger related costs	5,620		14,487
Other Cost and Expense, Operating	70,844	65,372	208,336	200,484
Utilities Operating Expense, Maintenance	11,208	12,533	45,172	52,594
Depreciation, Depletion and Amortization, Nonproduction	68,849	66,975	207,915	201,096
Taxes, Other	8,213	9,743	27,804	26,793
OPERATING INCOME	305,216	346,225	504,936	545,900
SPPC Total
Segment Reporting Information [Line Items]
Operating Revenues	227,006	224,150	633,872	627,429
Energy Costs:
Fuel for power generation	54,827	47,324	141,277	115,137
Purchased power	33,388	33,999	114,755	98,400
Gas purchased for resale	7,383	5,382	62,277	46,491
Deferred energy	(9,889)	(6,351)	(66,538)	(14,824)
Energy efficiency program costs	2,044	4,092	5,679	11,143
Regulatory Disallowances	5,469		5,469
Total Costs	93,222	84,446	262,919	256,347
Gross Margin	133,784	139,704	370,953	371,082
Merger related costs	2,008		5,528
Other Cost and Expense, Operating	34,394	34,128	106,455	104,214
Utilities Operating Expense, Maintenance	5,968	6,481	20,956	23,596
Depreciation, Depletion and Amortization, Nonproduction	27,952	27,537	83,772	80,594
Taxes, Other	5,944	5,894	18,414	17,382
OPERATING INCOME	57,518	65,664	135,828	145,296
SPPC Electric
Segment Reporting Information [Line Items]
Electric Domestic Regulated Revenue	213,463	212,073	560,392	549,886
Energy Costs:
Fuel for power generation	54,827	47,324	141,277	115,137
Purchased power	33,388	33,999	114,755	98,400
Deferred energy	(7,925)	(5,498)	(44,223)	(13,854)
Energy efficiency program costs	2,044	4,092	5,679	11,143
Regulatory Disallowances	5,469		5,469
Total Costs	87,803	79,917	222,957	210,826
Gross Margin	125,660	132,156	337,435	339,060
SPPC Gas
Segment Reporting Information [Line Items]
Gas Domestic Regulated Revenue	13,543	12,077	73,480	77,543
Energy Costs:
Gas purchased for resale	7,383	5,382	62,277	46,491
Deferred energy	(1,964)	(853)	(22,315)	(970)
Total Costs	5,419	4,529	39,962	45,521
Gross Margin	$ 8,124	$ 7,548	$ 33,518	$ 32,022

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MERGER RELATED ACTIVITIES (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Merger Related Activities [Line Items]
Merger related costs	$ 7,857,000	$ 0	$ 21,409,000	$ 0
Nevada Power Company
Merger Related Activities [Line Items]
Merger related costs	5,620,000	0	14,487,000	0
Sierra Pacific Power Company
Merger Related Activities [Line Items]
Merger related costs	2,008,000	0	5,528,000	0
MidAmerican Merger
Merger Related Activities [Line Items]
Merger Agreement Date			May 29, 2013
Expected Merger Closing Date			in late 2013 or first quarter of 2014
Merger Closing Conditions			the approval of the MidAmerican Merger Agreement by the holders of a majority of the outstanding shares of NVE common stock. On September 25, 2013, NVE’s stockholders approved the MidAmerican Merger Agreement. Consequently, this closing condition has been satisfied; the receipt of regulatory approvals and other consents required to consummate the MidAmerican Merger, including, among others, approvals from the PUCN and the FERC on terms and conditions specified in the MidAmerican Merger Agreement (in July 2013, filings were made with the PUCN and FERC. See Note 4, Regulatory Actions, for further details of these filings); the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. On July 22, 2013, NVE was advised that the Department of Justice and the U.S. Federal Trade Commission had terminated the applicable waiting period under the Hart-Scott-Rodino Act.  Consequently, the closing condition with respect to the Hart-Scott-Rodino Act has been satisfied; the absence of the occurrence of a company material adverse effect (as defined in the MidAmerican Merger Agreement) after the date of the MidAmerican Merger Agreement; and other customary closing conditions.
Merger Termination Right			The MidAmerican Merger Agreement contains certain termination rights and fees for both NVE and MEHC. In the event of termination of the MidAmerican Merger under certain circumstances, NVE may be obligated to pay MEHC a termination fee of up to $169.7 million.
Merger Termination Fee	169,700,000		169,700,000
Merger Share Exchange Ratio			$ 23.75
Shareholder approval date	September 25, 2013		September 25, 2013
Filing Date of PUCN filing			July 2013
Filing Date of FERC filing			July 2013
Satisfaction date of Hart Scott Rodino Condition			July 22, 2013
Change of Control Description of Debt			As a result, NVE, NPC and SPPC will be required to offer to purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing.
Merger Restrictions			The MidAmerican Merger Agreement contains customary representations, warranties and covenants for both NVE and MEHC. These covenants include an obligation for us, subject to certain exceptions, to conduct our business in a manner substantially consistent with our current practice. In addition, the covenants contain several restrictions that apply unless MEHC’s consent is received, including limitations on making certain business acquisitions, limitations on our total capital spending, limitations on the extent to which we may obtain financing through long-term debt or equity issuances and limitations on increasing our common stock dividend payout.
Merger Description			On May 29, 2013, NVE entered into the MidAmerican Merger Agreement.  The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation.  Once merged, NVE will become an indirect wholly owned subsidiary of MEHC.  The closing is expected to occur in late 2013 or during the first quarter of 2014.
MidAmerican Merger | Parent Company
Merger Related Activities [Line Items]
Debt required to be tendered	315,000,000		315,000,000
Average interest rate of debt required to be tendered			6.25%
MidAmerican Merger | Nevada Power Company
Merger Related Activities [Line Items]
Debt required to be tendered	3,100,000,000		3,100,000,000
Average interest rate of debt required to be tendered			6.42%
MidAmerican Merger | Sierra Pacific Power Company
Merger Related Activities [Line Items]
Debt required to be tendered	$ 951,700,000		$ 951,700,000
Average interest rate of debt required to be tendered			5.51%
One Company Merger | Nevada Power Company
Merger Related Activities [Line Items]
Merger Description			NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC. The One Company Merger is subject to approval by the PUCN and FERC.
One Company Merger | Sierra Pacific Power Company
Merger Related Activities [Line Items]
Merger Description			NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC. The One Company Merger is subject to approval by the PUCN and FERC.

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $) In Billions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 5.6	$ 5.9
Nevada Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	3.7	4.1
Sierra Pacific Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 1.3	$ 1.3

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REGULATORY, General Rate Cases (Details) (GRC [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
SPPC Electric
Summary of General Rate Case [Line Items]
Anticipated Effective Date of Rate Filing	January 1, 2014
Requested Increase Decrease In General Rates	$ (4.7)
Percentage Overall Increase Decrease In General Rates	(0.70%)
Requested Rate Of Return	7.74%
Requested Return On Equity	10.40%
General Rate Case Hearing Date	October 2013
SPPC Gas
Summary of General Rate Case [Line Items]
Anticipated Effective Date of Rate Filing	January 1, 2014
Requested Increase Decrease In General Rates	$ 6.0
Percentage Overall Increase Decrease In General Rates	6.10%
Requested Rate Of Return	7.72%
Requested Return On Equity	10.35%
General Rate Case Hearing Date	October 2013

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COMMON STOCK AND OTHER PAID-IN CAPITAL (Tables)

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Dividend Declarations

The following dividend declarations were made by the BOD of NVE:

Declaration Date	Amount	Payable Date	Shareholders of Record Date
February 7, 2013	$0.19	March 20, 2013	March 5, 2013
May 8, 2013	$0.19	June 19, 2013	June 4, 2013
August 1, 2013	$0.19	September 18, 2013	September 3, 2013
November 6, 2013	$0.19	December 18, 2013	December 3, 2013

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$ 271,942	$ 304,782
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	291,687	281,690
Deferred Income Taxes and Tax Credits	152,280	187,229
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(7,730)	(6,666)
Deferred energy	(218,156)	(18,702)
Non Cash Regulatory Disallowance	17,335	0
Amortization of other regulatory assets	134,846	114,626
Deferred rate increase	9,241	2,252
Other Noncash Income (Expense)	3,649	(50,012)
Changes in certain assets and liabilities:
Accounts receivable	(101,079)	(151,420)
Materials, supplies and fuel	16,909	(18,034)
Other current assets	(8,292)	(10,390)
Accounts payable	7,042	22,646
Increase (Decrease) in Pension and Postretirement Obligations	(17,563)	(12,946)
Other current liabilities	(594)	(23,643)
Other deferred assets	(3,634)	(3,572)
Other regulatory assets	(3,276)	34,420
Other deferred liabilities	9,099	(8,066)
Net Cash from Operating Activities	553,706	644,194
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)	(267,798)	(387,790)
Customer advances for construction	921	(1,508)
Contributions in aid of construction	38,714	63,864
Investments and other property - net	(5,144)	217
Net Cash Provided by (Used in) Investing Activities	(233,307)	(325,217)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt	247,245	130,764
Retirement of long-term debt	(354,443)	(272,353)
Sale of Common Stock	2,133	0
Common stock repurchased	(6,329)	(4,509)
Dividends paid	(134,250)	(110,920)
Net Cash from/(used by) Financing Activities	(245,644)	(257,018)
Net Increase (Decrease) in Cash and Cash Equivalents	74,755	61,959
Beginning Balance in Cash and Cash Equivalents	298,271	145,944
Ending Balance in Cash and Cash Equivalents	373,026	207,903
Cash paid during period for:
Interest	233,502	237,262
Income taxes	2	151
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	141,214	132,112
Issuance of treasury stock	13,102	0
Nevada Power Company
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	228,552	256,151
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	207,915	201,096
Deferred Income Taxes and Tax Credits	126,080	150,289
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(6,151)	(4,823)
Deferred energy	(152,534)	(7,335)
Non Cash Regulatory Disallowance	11,866	0
Amortization of other regulatory assets	75,893	56,012
Deferred rate increase	9,241	2,252
Other Noncash Income (Expense)	(722)	(35,553)
Changes in certain assets and liabilities:
Accounts receivable	(118,863)	(164,858)
Materials, supplies and fuel	7,017	(5,119)
Other current assets	(7,222)	(3,715)
Accounts payable	20,856	53,985
Increase (Decrease) in Pension and Postretirement Obligations	3,048	3,708
Other current liabilities	(5,819)	(25,246)
Other deferred assets	(1,613)	(2,412)
Other regulatory assets	26	50,008
Other deferred liabilities	1,613	(10,412)
Net Cash from Operating Activities	399,183	514,028
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)	(159,063)	(232,608)
Customer advances for construction	1,035	713
Contributions in aid of construction	20,263	34,274
Investments and other property - net	1,595	193
Net Cash Provided by (Used in) Investing Activities	(136,170)	(197,428)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt	(261)	132,259
Retirement of long-term debt	(103,718)	(271,241)
Dividends paid	(105,000)	(119,000)
Net Cash from/(used by) Financing Activities	(208,979)	(257,982)
Net Increase (Decrease) in Cash and Cash Equivalents	54,034	58,618
Beginning Balance in Cash and Cash Equivalents	201,202	65,887
Ending Balance in Cash and Cash Equivalents	255,236	124,505
Cash paid during period for:
Interest	174,050	177,459
Income taxes	1	1
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	119,943	111,052
Sierra Pacific Power Company
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	61,931	65,750
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation, Depletion and Amortization, Nonproduction	83,772	80,594
Deferred Income Taxes and Tax Credits	32,847	42,809
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(1,579)	(1,843)
Deferred energy	(65,622)	(11,367)
Non Cash Regulatory Disallowance	5,469	0
Amortization of other regulatory assets	58,769	58,484
Other Noncash Income (Expense)	185	(15,532)
Changes in certain assets and liabilities:
Accounts receivable	17,700	13,452
Materials, supplies and fuel	9,892	(12,915)
Other current assets	(934)	(6,512)
Accounts payable	(16,893)	(21,002)
Increase (Decrease) in Pension and Postretirement Obligations	(23,544)	(18,477)
Other current liabilities	2,141	(3,522)
Other deferred assets	(2,021)	(1,160)
Other regulatory assets	(3,302)	(15,588)
Other deferred liabilities	(1,876)	(6,282)
Net Cash from Operating Activities	156,935	146,889
CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)	(108,735)	(155,182)
Customer advances for construction	(114)	(2,221)
Contributions in aid of construction	18,451	29,590
Investments and other property - net	24	24
Net Cash Provided by (Used in) Investing Activities	(90,374)	(127,789)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt	247,506	(1,447)
Retirement of long-term debt	(250,725)	(1,112)
Dividends paid	(40,000)	(20,000)
Net Cash from/(used by) Financing Activities	(43,219)	(22,559)
Net Increase (Decrease) in Cash and Cash Equivalents	23,342	(3,459)
Beginning Balance in Cash and Cash Equivalents	60,786	55,195
Ending Balance in Cash and Cash Equivalents	84,128	51,736
Cash paid during period for:
Interest	45,554	45,772
Noncash Investing and Financing Items [Abstract]
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	$ 21,271	$ 21,060

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (133)	$ (74)	$ (398)	$ (246)
Market value of risk management assets and liabilities	(154)	91	(261)	355
Unrealized net gain/(loss) on investments	(49)	0	(18)	0
Nevada Power Company
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	(52)	(33)	(156)	(103)
Sierra Pacific Power Company
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (32)	$ (22)	$ (95)	$ (68)

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SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

SEGMENT INFORMATION

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 costs, energy efficiency program costs and regulatory disallowances provides a measure of income available to support the other operating expenses of the Utilities.  See Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements in the 2012 Form 10-K for further information regarding energy efficiency program costs.  

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

Three Months Ended
September 30, 2013
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	1,013,151		$	3		$	786,142		$	227,006		$	213,463		$	13,543
Energy Costs:
Fuel for power generation	217,954			—			163,127			54,827			54,827			—
Purchased power	205,970			—			172,582			33,388			33,388			—
Gas purchased for resale	7,383			—			—			7,383			—			7,383
Deferred energy	(55,270		)	—			(45,381		)	(9,889		)	(7,925		)	(1,964		)
Energy efficiency program costs	16,042			—			13,998			2,044			2,044			—
Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
Total Costs	$	409,414		$	—		$	316,192		$	93,222		$	87,803		$	5,419
Gross Margin	$	603,737		$	3		$	469,950		$	133,784		$	125,660		$	8,124
Merger-related costs	7,857			229			5,620			2,008
Other operating expenses	106,068			830			70,844			34,394
Maintenance	17,176			—			11,208			5,968
Depreciation and amortization	96,801			—			68,849			27,952
Taxes other than income	14,214			57			8,213			5,944
Operating Income (Loss)	$	361,621		$	(1,113	)	$	305,216		$	57,518

Nine Months Ended
September 30, 2013
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	2,329,011		$	10		$	1,695,129		$	633,872		$	560,392		$	73,480
Energy Costs:
Fuel for power generation	554,181			—			412,904			141,277			141,277			—
Purchased power	498,141			—			383,386			114,755			114,755			—
Gas purchased for resale	62,277			—			—			62,277			—			62,277
Deferred energy	(221,022		)	—			(154,484		)	(66,538		)	(44,223		)	(22,315		)
Energy efficiency program costs	38,486			—			32,807			5,679			5,679			—
Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
Total Costs	$	949,398		$	—		$	686,479		$	262,919		$	222,957		$	39,962
Gross Margin	$	1,379,613		$	10		$	1,008,650		$	370,953		$	337,435		$	33,518
Merger-related costs	21,409			1,394			14,487			5,528
Other operating expenses	317,538			2,747			208,336			106,455
Maintenance	66,128			—			45,172			20,956
Depreciation and amortization	291,687			—			207,915			83,772
Taxes other than income	46,536			318			27,804			18,414
Operating Income (Loss)	$	636,315		$	(4,449	)	$	504,936		$	135,828

Three Months Ended
September 30, 2012
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	1,026,488		$	4		$	802,334		$	224,150		$	212,073		$	12,077
Energy Costs:
Fuel for power generation	171,316			—			123,992			47,324			47,324			—
Purchased power	205,686			—			171,687			33,999			33,999			—
Gas purchased for resale	5,382			—			—			5,382			—			5,382
Deferred energy	(29,036		)	—			(22,685		)	(6,351		)	(5,498		)	(853		)
Energy efficiency program costs	32,584			—			28,492			4,092			4,092			—
Total Costs	$	385,932		$	—		$	301,486		$	84,446		$	79,917		$	4,529
Gross Margin	$	640,556		$	4		$	500,848		$	139,704		$	132,156		$	7,548
Other operating expenses	100,108			608			65,372			34,128
Maintenance	19,014			—			12,533			6,481
Depreciation and amortization	94,512			—			66,975			27,537
Taxes other than income	15,682			45			9,743			5,894
Operating Income (Loss)	$	411,240		$	(649	)	$	346,225		$	65,664

Nine Months Ended
September 30, 2012
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	2,378,606		$	12		$	1,751,165		$	627,429		$	549,886		$	77,543
Energy Costs:
Fuel for power generation	400,936			—			285,799			115,137			115,137			—
Purchased power	486,894			—			388,494			98,400			98,400			—
Gas purchased for resale	46,491			—			—			46,491			—			46,491
Deferred Energy	(30,285		)	—			(15,461		)	(14,824		)	(13,854		)	(970		)
Energy efficiency program costs	76,609			—			65,466			11,143			11,143			—
Total Costs	$	980,645		$	—		$	724,298		$	256,347		$	210,826		$	45,521
Gross Margin	$	1,397,961		$	12		$	1,026,867		$	371,082		$	339,060		$	32,022
Other operating expenses	307,080			2,382			200,484			104,214
Maintenance	76,190			—			52,594			23,596
Depreciation and amortization	281,690			—			201,096			80,594
Taxes other than income	44,457			282			26,793			17,382
Operating Income (Loss)	$	688,544		$	(2,652	)	$	545,900		$	145,296

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 Company, Inc. and Sierra Gas Holding Company.  All intercompany balances and 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.

In the opinion of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown.  These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in the 2012 Form 10-K.

The results of operations and cash flows of NVE, NPC and SPPC for the nine months ended September 30, 2013, are not necessarily indicative of the results to be expected for the full year.

Accounting Policies

Consolidations of VIEs

To identify potential variable interests, management reviewed 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 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 September 30, 2013, 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.

Recent Accounting Standards Update

Derivatives and Hedging (ASC815) 

In July 2013, the FASB amended its existing guidance related to hedge accounting.  The amendment permits the Fed Funds Effective Swap Rate (OIS) to be used as a U.S benchmark interest rate for hedge accounting purposes under ASC 815, in addition, to the current approved U.S. rates which include interest rates on direct Treasury obligations of the U.S. government (UST) and LIBOR.  The amendment is effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013.    The adoption of this guidance did not have an impact on the presentation of the consolidated financial statements or disclosure requirements for NVE and the Utilities.

Income Taxes (ASC 740)

In July 2013, the FASB amended its existing guidance related to the presentation of an unrecognized tax benefit on the financial statements.  ASC 740, Income Taxes, does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a NOL carryforward, a similar tax loss, or a tax credit carryforward exists.  As a result, there is diversity in practice in the presentation of unrecognized tax benefits.  The objective of the amendment is to eliminate the diversity in practice, requiring the unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward with certain exceptions.  The amendment can be applied prospectively or retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 for public entities.  NVE and the Utilities have elected to early adopt this amendment prospectively as of September 30, 2013, presenting their unrecognized tax benefit as a reduction to their NOL deferred tax asset. The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.

Federal Income Tax Regulations

In September 2013, the Internal Revenue Service and the U.S. Treasury Department released final tax regulations on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014.  NVE and the Utilities continue to evaluate the effects of the tangible property regulations as well as the generation guidance in Revenue Procedure 2013-24, but do not believe that these tax regulations will have a material impact on the presentation of the financial statements for NVE and the Utilities.

Other Comprehensive Income (ASC 220)

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.  In February 2013, the FASB reinstated certain portions of the deferred amendment.  The reinstated amendment is applied prospectively and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance did not have an impact on the presentation of the financial statements for NVE and the Utilities.

Balance Sheet Offsetting Disclosures (ASC 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 includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements.  The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance did not have an impact on the disclosure requirements for NVE and the Utilities.

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REGULATORY ACTIONS, Deferred Energy (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Nevada Deferred Energy
Cumulative balance authorized in DEAA	$ (152,990)
Amortization	111,977
Deferred Energy Under Collection	118,397	[1]
Nevada Deferred Energy Balance at period end	77,384
Reinstatement of deferred energy (effective 6/07, 10 years)	89,906
Total Deferred Energy	167,290
Deferred Assets
Deferred energy costs current	82,235		0
Deferred Energy Costs Non Current	85,055		87,072
Liabilities, Current [Abstract]
Deferred energy	0		136,865
NPC Electric
Nevada Deferred Energy
Cumulative balance authorized in DEAA	(102,227)
Amortization	69,288
Deferred Energy Under Collection	95,465	[1]
Nevada Deferred Energy Balance at period end	62,526
Reinstatement of deferred energy (effective 6/07, 10 years)	89,906
Total Deferred Energy	152,432
Deferred Assets
Deferred energy costs current	68,391
Deferred Energy Costs Non Current	84,041
SPPC Electric
Nevada Deferred Energy
Cumulative balance authorized in DEAA	(32,693)
Amortization	23,695
Deferred Energy Under Collection	19,697	[1]
Nevada Deferred Energy Balance at period end	10,699
Reinstatement of deferred energy (effective 6/07, 10 years)	0
Total Deferred Energy	10,699
Deferred Assets
Deferred Energy Electric Current	10,322
Deferred Energy Costs Non Current	377
SPPC Gas
Nevada Deferred Energy
Cumulative balance authorized in DEAA	(18,070)
Amortization	18,994
Deferred Energy Under Collection	3,235	[1]
Nevada Deferred Energy Balance at period end	4,159
Reinstatement of deferred energy (effective 6/07, 10 years)	0
Total Deferred Energy	4,159
Deferred Assets
Deferred Energy Gas Current	3,522
Deferred Energy Costs Gas Non Current	$ 637

[1] These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting Policies, Deferred Energy Accounting, of the Notes to the Financial Statements in the 2012 Form 10-K.

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REGULATORY ACTIONS, FERC Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Nevada Power Company | FERC Filing 2012 [Member]
FERC Matters [Abstract]
Transmission Rate Case Filing Date	October 2012
Anticipated Effective Date of Rate Filing	June 1, 2013
Nevada Power Company | FERC Filing 2013 [Member]
FERC Matters [Abstract]
Transmission Rate Case Filing Date	May 2013
Anticipated Effective Date of Rate Filing	January 1, 2014
Intervenor Filing Date	July 16, 2013
Sierra Pacific Power Company | FERC Filing 2012 [Member]
FERC Matters [Abstract]
TransmissionRateCase	$ 1.5
Transmission Rate Case Filing Date	October 2012
Anticipated Effective Date of Rate Filing	June 1, 2013
FERC approval date	August 29, 2013
Sierra Pacific Power Company | FERC Filing 2013 [Member]
FERC Matters [Abstract]
Transmission Rate Case Filing Date	May 2013
Anticipated Effective Date of Rate Filing	January 1, 2014
Intervenor Filing Date	July 16, 2013

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COMMITMENTS AND CONTINGENCIES, Litigation Contingencies and Other Commitments (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Capital Projects
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%
Nevada Power Company [Member]
Royalty claim [Abstract]
Damages sought in DC Lawsuit	$ 600,000,000
Minimum punitive damages sought in DC Lawsuit	1,000,000,000
November 2005 Land Investors [Abstract]
Amount awarded unpaid rent	1,000,000
Amount awarded inverse condemnation and interest	5,100,000
Nevada Power Company [Member] | Capital Projects
ON Line TUA [Abstract]
Capitalized construction costs	370,800,000
Nevada Power Company [Member] | Navajo Generating Station
Royalty claim [Abstract]
Ownership interest in generating stations (in hundredths)	11.30%
Sierra Pacific Power Company
Farad Dam [Abstract]
Number of hydro generating units sold	4
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	3 years
ReplacementCost	19,800,000
Sierra Pacific Power Company | Capital Projects
ON Line TUA [Abstract]
Capitalized construction costs	$ 19,400,000

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
OTHER INCOME (EXPENSE):
AFUDC-debt	$ 1,957	$ 1,976	$ 5,770	$ 5,479
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	(133)	(74)	(398)	(246)
Market value of risk management assets and liabilities	(154)	91	(261)	355
Unrealized net gain/(loss) on investments	(49)	0	(18)	0
Nevada Power Company
OTHER INCOME (EXPENSE):
AFUDC-debt	1,520	1,528	4,763	4,021
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	(52)	(33)	(156)	(103)
Sierra Pacific Power Company
OTHER INCOME (EXPENSE):
AFUDC-debt	437	448	1,007	1,458
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (32)	$ (22)	$ (95)	$ (68)

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FAIR VALUE OF FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Disclosures

FAIR VALUE OF FINANCIAL INSTRUMENTS

The September 30, 2013 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments. As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2012 Form 10-K, investments held in Rabbi Trust continues to be considered Level 1 in the fair value hierarchy.

The total fair value of NVE’s consolidated long-term debt at September 30, 2013, is estimated to be $5.6 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 $5.9 billion as of December 31, 2012.

The total fair value of NPC’s consolidated long-term debt at September 30, 2013, is estimated to be $3.7 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 $4.1 billion at December 31, 2012.

The total fair value of SPPC’s consolidated long-term debt at September 30, 2013, 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, 2012.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	$ 9,643	$ 8,748
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	235,999,750
Common stock, shares outstanding (in shares)	235,581,074	235,079,156
Treasury stock (in shares)	418,675	920,594
Nevada Power Company
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	8,584	7,622
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
Sierra Pacific Power Company
Current Assets:
Allowance for Doubtful Accounts Receivable, Current	$ 1,059	$ 1,126
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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
OPERATING REVENUES:
OPERATING REVENUES	$ 1,013,151		$ 1,026,488		$ 2,329,011		$ 2,378,606
Operating Expenses
Fuel for power generation	217,954		171,316		554,181		400,936
Purchased power	205,970		205,686		498,141		486,894
Gas purchased for resale	7,383		5,382		62,277		46,491
Deferred energy	(55,270)		(29,036)		(221,022)		(30,285)
Energy efficiency program costs	16,042		32,584		38,486		76,609
Regulatory Disallowances	17,335		0		17,335		0
Merger related costs	7,857		0		21,409		0
Other operating expenses	106,068		100,108		317,538		307,080
Maintenance	17,176		19,014		66,128		76,190
Depreciation and amortization	96,801		94,512		291,687		281,690
Taxes other than income	14,214		15,682		46,536		44,457
Total Operating Expenses	651,530		615,248		1,692,696		1,690,062
OPERATING INCOME	361,621		411,240		636,315		688,544
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt)	(74,438)		(73,667)		(221,305)		(226,162)
Interest Income (Expense) on Regulatory Items	(281)		(2,024)		(1,124)		(6,203)
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	2,591		2,415		7,730		6,666
Other Nonoperating Income	3,239		8,827		10,872		19,312
Other expense	(3,829)		(4,209)		(12,116)		(11,909)
Total Other Income (Expense)	(72,718)		(68,658)		(215,943)		(218,296)
Income Before Income Tax Expense	288,903		342,582		420,372		470,248
Income Tax Expense (Benefit)	101,669		119,412		148,430		165,466
NET INCOME	187,234		223,170		271,942		304,782
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization	246		155		738		464
Change in market value of risk management assets and liabilities	(11)		(193)		485		(668)
Unrealized net gain/(loss) on investment	98		0		33		0
OTHER COMPREHENSIVE INCOME(LOSS)	333		(38)		1,256		(204)
COMPREHENSIVE INCOME	187,567		223,132		273,198		304,578
Amount per share basic and diluted
Net income per share - basic, in dollars per share	$ 0.79		$ 0.95		$ 1.16		$ 1.29
Net income per share - diluted, in dollars per share	$ 0.79		$ 0.94		$ 1.15		$ 1.28
Weighted Average Shares of Common Stock Outstanding - basic	235,578,310		235,961,402		235,421,933		235,986,874
Weighted Average Shares of Common Stock Outstanding - diluted	237,605,514	[1]	238,121,732	[1]	237,339,039	[1]	237,850,530	[1]
Dividends Declared Per Share of Common Stock	$ 0.19		$ 0.17		$ 0.57		$ 0.47
Nevada Power Company
OPERATING REVENUES:
OPERATING REVENUES	786,142		802,334		1,695,129		1,751,165
Operating Expenses
Fuel for power generation	163,127		123,992		412,904		285,799
Purchased power	172,582		171,687		383,386		388,494
Deferred energy	(45,381)		(22,685)		(154,484)		(15,461)
Energy efficiency program costs	13,998		28,492		32,807		65,466
Regulatory Disallowances	11,866		0		11,866		0
Merger related costs	5,620		0		14,487		0
Other operating expenses	70,844		65,372		208,336		200,484
Maintenance	11,208		12,533		45,172		52,594
Depreciation and amortization	68,849		66,975		207,915		201,096
Taxes other than income	8,213		9,743		27,804		26,793
Total Operating Expenses	480,926		456,109		1,190,193		1,205,265
OPERATING INCOME	305,216		346,225		504,936		545,900
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt)	(52,856)		(51,784)		(155,758)		(158,791)
Interest Income (Expense) on Regulatory Items	(194)		(1,623)		(1,177)		(5,488)
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	1,959		1,833		6,151		4,823
Other Nonoperating Income	1,948		7,096		5,330		14,197
Other expense	(1,966)		(2,823)		(6,200)		(7,162)
Total Other Income (Expense)	(51,109)		(47,301)		(151,654)		(152,421)
Income Before Income Tax Expense	254,107		298,924		353,282		393,479
Income Tax Expense (Benefit)	89,665		103,754		124,730		137,328
NET INCOME	164,442		195,170		228,552		256,151
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization	96		65		290		192
COMPREHENSIVE INCOME	164,538		195,235		228,842		256,343
Sierra Pacific Power Company
OPERATING REVENUES:
Electric	213,463		212,073		560,392		549,886
Gas	13,543		12,077		73,480		77,543
OPERATING REVENUES	227,006		224,150		633,872		627,429
Operating Expenses
Fuel for power generation	54,827		47,324		141,277		115,137
Purchased power	33,388		33,999		114,755		98,400
Gas purchased for resale	7,383		5,382		62,277		46,491
Deferral of energy - electric-net	(7,925)		(5,498)		(44,223)		(13,854)
Deferral of energy - gas-net	(1,964)		(853)		(22,315)		(970)
Energy efficiency program costs	2,044		4,092		5,679		11,143
Regulatory Disallowances	5,469		0		5,469		0
Merger related costs	2,008		0		5,528		0
Other operating expenses	34,394		34,128		106,455		104,214
Maintenance	5,968		6,481		20,956		23,596
Depreciation and amortization	27,952		27,537		83,772		80,594
Taxes other than income	5,944		5,894		18,414		17,382
Total Operating Expenses	169,488		158,486		498,044		482,133
OPERATING INCOME	57,518		65,664		135,828		145,296
OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt)	(15,122)		(15,298)		(46,020)		(47,650)
Interest Income (Expense) on Regulatory Items	(87)		(401)		53		(715)
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	632		582		1,579		1,843
Other Nonoperating Income	983		1,399		4,641		4,181
Other expense	(982)		(998)		(3,803)		(3,609)
Total Other Income (Expense)	(14,576)		(14,716)		(43,550)		(45,950)
Income Before Income Tax Expense	42,942		50,948		92,278		99,346
Income Tax Expense (Benefit)	13,691		16,521		30,347		33,596
NET INCOME	29,251		34,427		61,931		65,750
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization	59		42		176		127
COMPREHENSIVE INCOME	$ 29,310		$ 34,469		$ 62,107		$ 65,877

[1] The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending September 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively.

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REGULATORY ACTIONS, Merger Related and Financing Application (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Nevada Power Company
Merger Related Activities [Line Items]
Financing Application Date	May 2013
New Authority Requested	$ 705,000,000
Amount Of Requested New Debt Consolidated Authority	1,100,000,000
Amount Of Requested Refinance Consolidated Authority	1,500,000,000
Amount Of Existing Revolver	1,300,000,000
Additional Authority Requested If Extended	255,000,000
Sierra Pacific Power Company
Merger Related Activities [Line Items]
Financing Application Date	May 2013
New Authority Requested	705,000,000
Amount Of Requested New Debt Consolidated Authority	1,100,000,000
Amount Of Requested Refinance Consolidated Authority	1,500,000,000
Amount Of Existing Revolver	$ 600,000,000
MidAmerican Merger | Nevada Power Company
Merger Related Activities [Line Items]
Filing Date of PUCN filing	July 2013
Filing Date of FERC filing	July 12, 2013
Expected Authorization Date FERC	December 19, 2013
Expected Authorization Date PUCN	January 2014
Expected Hearing Date	Nov. 01, 2013
Days To Respond	180 days
AdditionalDaysToRespond	180 days
MidAmerican Merger | Sierra Pacific Power Company
Merger Related Activities [Line Items]
Filing Date of PUCN filing	July 2013
Filing Date of FERC filing	July 12, 2013
Expected Authorization Date FERC	December 19, 2013
Expected Authorization Date PUCN	January 2014
Expected Hearing Date	Nov. 01, 2013
Days To Respond	180 days
AdditionalDaysToRespond	180 days
One Company Merger | Nevada Power Company
Merger Related Activities [Line Items]
Filing Date of PUCN filing	May 2013
Filing Date of FERC filing	May 2013
Expected Hearing Date	Feb. 01, 2014
One Company Merger | Sierra Pacific Power Company
Merger Related Activities [Line Items]
Filing Date of PUCN filing	May 2013
Filing Date of FERC filing	May 2013
Expected Hearing Date	Feb. 01, 2014

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RETIREMENT PLAN AND POST-RETIREMENT BENEFITS (Tables)

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs

This summary is based on a December 31, measurement date (dollars in thousands):

NVE
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	5,132		$	4,406		$	660		$	595
Interest cost	9,303			10,228			1,677			1,905
Expected return on plan assets	(12,708		)	(12,447		)	(1,687		)	(1,563		)
Amortization of prior service cost	(720		)	(724		)	(952		)	(987		)
Amortization of net loss	4,797			3,473			890			731
Net periodic benefit cost	$	5,804		$	4,936		$	588		$	681

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	15,396		$	13,220		$	1,980		$	1,787
Interest cost	27,911			30,684			5,030			5,715
Expected return on plan assets	(38,124		)	(37,341		)	(5,060		)	(4,690		)
Amortization of prior service cost	(2,162		)	(2,173		)	(2,857		)	(2,961		)
Amortization of net loss	14,391			10,418			2,671			2,193
Net periodic benefit cost	$	17,412		$	14,808		$	1,764		$	2,044

The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 34.5% and 35.0% respectively.

NPC
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	2,761		$	2,358		$	389		$	350
Interest cost	4,453			4,881			556			602
Expected return on plan assets	(6,270		)	(6,237		)	(631		)	(592		)
Amortization of prior service cost	(453		)	(456		)	(23		)	229
Amortization of net loss	2,117			1,363			289			221
Net periodic benefit cost	$	2,608		$	1,909		$	580		$	810

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	8,283		$	7,072		$	1,167		$	1,050
Interest cost	13,358			14,643			1,667			1,807
Expected return on plan assets	(18,810		)	(18,711		)	(1,892		)	(1,775		)
Amortization of prior service cost	(1,358		)	(1,367		)	(69		)	687
Amortization of net loss	6,351			4,089			867			662
Net periodic benefit cost	$	7,824		$	5,726		$	1,740		$	2,431

The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.9% and 36.9% respectively.

SPPC
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	1,926		$	1,695		$	251		$	227
Interest cost	4,558			5,043			1,104			1,283
Expected return on plan assets	(6,162		)	(5,937		)	(1,022		)	(941		)
Amortization of prior service cost	(277		)	(277		)	(933		)	(1,220		)
Amortization of net loss	2,501			2,026			592			504
Net periodic benefit cost	$	2,546		$	2,550		$	(8	)	$	(147	)

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	5,778		$	5,086		$	752		$	682
Interest cost	13,676			15,130			3,310			3,848
Expected return on plan assets	(18,486		)	(17,813		)	(3,065		)	(2,823		)
Amortization of prior service cost	(831		)	(831		)	(2,798		)	(3,658		)
Amortization of net loss	7,502			6,078			1,777			1,511
Net periodic benefit cost	$	7,639		$	7,650		$	(24	)	$	(440	)

The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 and was 35.6% and 35.1%, respectively.

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COMMON STOCK AND OTHER PAID-IN CAPITAL (Details) (USD $)	3 Months Ended				9 Months Ended		0 Months Ended			9 Months Ended			0 Months Ended	9 Months Ended	0 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Nov. 06, 2013 Subsequent Event	Dec. 18, 2013 Subsequent Event Scenario, Forecast	Dec. 03, 2013 Subsequent Event Scenario, Forecast	Sep. 30, 2013 Treasury stock	Sep. 30, 2012 Treasury stock	Sep. 30, 2013 Nevada Power Company	Nov. 06, 2013 Nevada Power Company Subsequent Event	Sep. 30, 2013 Sierra Pacific Power Company	Nov. 06, 2013 Sierra Pacific Power Company Subsequent Event
Dividends Payable [Line Items]
Dividends Declared Per Share of Common Stock	$ 0.19	$ 0.19	$ 0.19	$ 0.17	$ 0.57	$ 0.47	$ 0.19
Dividends [Abstract]
Dividends Payable, Date to be Paid, Day, Month and Year	Sep. 18, 2013	Jun. 19, 2013	Mar. 20, 2013					Dec. 18, 2013
Dividends Payable, Date of Record, Day, Month and Year	Sep. 03, 2013	Jun. 04, 2013	Mar. 05, 2013						Dec. 03, 2013
Cash Dividends Paid to Parent Company by Consolidated Subsidiaries												$ 105,000,000		$ 40,000,000
Dividend declared to parent company													73,000,000		37,000,000
Declaration date	Aug. 01, 2013	May 08, 2013	Feb. 07, 2013				Nov. 06, 2013						Nov. 06, 2013		Nov. 06, 2013
Common stock repurchased (shares)										325,178	252,000
Common stock repurchased					$ (6,329,000)	$ (4,509,000)				$ (6,329,000)	$ (4,509,000)
Dividend Reinvestment and Employee Benefits (in shares)										827,097

XML

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS, Components of Net Periodic Cost and Expected Benefit Payments (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Average percentage of net periodic costs capitalized [Abstract]
Average percentage of net periodic costs capitalized (in hundredths)			34.50%	35.00%
DefinedBenefitPlanEffectOfPlanAmendmentOnAccumulatedBenefitObligation	$ 21,500,000		$ 21,500,000
United States Pension Plans of US Entity, Defined Benefit
Net periodic benefit cost [Abstract]
Service cost	5,132,000	4,406,000	15,396,000	13,220,000
Interest cost	9,303,000	10,228,000	27,911,000	30,684,000
Expected return on plan assets	(12,708,000)	(12,447,000)	(38,124,000)	(37,341,000)
Amortization of:
Prior service (credit)/cost	(720,000)	(724,000)	(2,162,000)	(2,173,000)
Actuarial (gain)/loss	4,797,000	3,473,000	14,391,000	10,418,000
Total net benefit cost	5,804,000	4,936,000	17,412,000	14,808,000
Average percentage of net periodic costs capitalized [Abstract]
PensionAndOtherPostretirementBenefitContributions			20,000,000	15,000,000
United States Postretirement Benefit Plans of US Entity, Defined Benefit
Net periodic benefit cost [Abstract]
Service cost	660,000	595,000	1,980,000	1,787,000
Interest cost	1,677,000	1,905,000	5,030,000	5,715,000
Expected return on plan assets	(1,687,000)	(1,563,000)	(5,060,000)	(4,690,000)
Amortization of:
Prior service (credit)/cost	(952,000)	(987,000)	(2,857,000)	(2,961,000)
Actuarial (gain)/loss	890,000	731,000	2,671,000	2,193,000
Total net benefit cost	588,000	681,000	1,764,000	2,044,000
Average percentage of net periodic costs capitalized [Abstract]
PensionAndOtherPostretirementBenefitContributions			5,000,000	7,100,000
Nevada Power Company
Average percentage of net periodic costs capitalized [Abstract]
Average percentage of net periodic costs capitalized (in hundredths)			35.90%	36.90%
Nevada Power Company | United States Pension Plans of US Entity, Defined Benefit
Net periodic benefit cost [Abstract]
Service cost	2,761,000	2,358,000	8,283,000	7,072,000
Interest cost	4,453,000	4,881,000	13,358,000	14,643,000
Expected return on plan assets	(6,270,000)	(6,237,000)	(18,810,000)	(18,711,000)
Amortization of:
Prior service (credit)/cost	(453,000)	(456,000)	(1,358,000)	(1,367,000)
Actuarial (gain)/loss	2,117,000	1,363,000	6,351,000	4,089,000
Total net benefit cost	2,608,000	1,909,000	7,824,000	5,726,000
Nevada Power Company | United States Postretirement Benefit Plans of US Entity, Defined Benefit
Net periodic benefit cost [Abstract]
Service cost	389,000	350,000	1,167,000	1,050,000
Interest cost	556,000	602,000	1,667,000	1,807,000
Expected return on plan assets	(631,000)	(592,000)	(1,892,000)	(1,775,000)
Amortization of:
Prior service (credit)/cost	(23,000)	229,000	(69,000)	687,000
Actuarial (gain)/loss	289,000	221,000	867,000	662,000
Total net benefit cost	580,000	810,000	1,740,000	2,431,000
Sierra Pacific Power Company
Average percentage of net periodic costs capitalized [Abstract]
Average percentage of net periodic costs capitalized (in hundredths)			35.60%	35.10%
Sierra Pacific Power Company | United States Pension Plans of US Entity, Defined Benefit
Net periodic benefit cost [Abstract]
Service cost	1,926,000	1,695,000	5,778,000	5,086,000
Interest cost	4,558,000	5,043,000	13,676,000	15,130,000
Expected return on plan assets	(6,162,000)	(5,937,000)	(18,486,000)	(17,813,000)
Amortization of:
Prior service (credit)/cost	(277,000)	(277,000)	(831,000)	(831,000)
Actuarial (gain)/loss	2,501,000	2,026,000	7,502,000	6,078,000
Total net benefit cost	2,546,000	2,550,000	7,639,000	7,650,000
Sierra Pacific Power Company | United States Postretirement Benefit Plans of US Entity, Defined Benefit
Net periodic benefit cost [Abstract]
Service cost	251,000	227,000	752,000	682,000
Interest cost	1,104,000	1,283,000	3,310,000	3,848,000
Expected return on plan assets	(1,022,000)	(941,000)	(3,065,000)	(2,823,000)
Amortization of:
Prior service (credit)/cost	(933,000)	(1,220,000)	(2,798,000)	(3,658,000)
Actuarial (gain)/loss	592,000	504,000	1,777,000	1,511,000
Total net benefit cost	$ (8,000)	$ (147,000)	$ (24,000)	$ (440,000)

XML

COMMITMENTS AND CONTINGENCIES, Environmental (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Environmental [Abstract]
Regional Haze	$ 77.1
Nevada Power Company
Environmental [Abstract]
Reclamation estimate of coal washing and load-out facility site	4.0
Nevada Power Company | Navajo Generating Station
Environmental [Abstract]
Ownership interest in generating stations (in hundredths)	11.30%
Regional Haze	1,100.0
Sierra Pacific Power Company | Valmy Generating Station
Environmental [Abstract]
Ownership interest in generating stations (in hundredths)	50.00%
Mercury Air Toxic Standards Costs	$ 6.4

XML

LONG-TERM DEBT

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Long-term Debt

LONG-TERM DEBT

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

				September 30,											December 31,
				2013											2012
Long-Term Debt:	Stated Rate		Maturity Date	Consolidated			NVE Holding Co.		NPC			SPPC			Consolidated			NVE Holding Co.		NPC			SPPC
Secured Debt
General and Refunding Mortgage Securities
NPC Series L	5.875	%	2015	$	250,000		$	—	$	250,000		$	—		$	250,000		$	—	$	250,000		$	—
NPC Series M	5.950	%	2016	210,000			—		210,000			—			210,000			—		210,000			—
NPC Series N	6.650	%	2036	370,000			—		370,000			—			370,000			—		370,000			—
NPC Series O	6.500	%	2018	325,000			—		325,000			—			325,000			—		325,000			—
NPC Series R	6.750	%	2037	350,000			—		350,000			—			350,000			—		350,000			—
NPC Series S	6.500	%	2018	500,000			—		500,000			—			500,000			—		500,000			—
NPC Series U	7.375	%	2014	125,000			—		125,000			—			125,000			—		125,000			—
NPC Series V	7.125	%	2019	500,000			—		500,000			—			500,000			—		500,000			—
NPC Series X	5.375	%	2040	250,000			—		250,000			—			250,000			—		250,000			—
NPC Series Y	5.450	%	2041	250,000			—		250,000			—			250,000			—		250,000			—
SPPC Series M	6.000	%	2016	450,000			—		—			450,000			450,000			—		—			450,000
SPPC Series P	6.750	%	2037	251,742			—		—			251,742			251,742			—		—			251,742
SPPC Series Q	5.450	%	2013	—			—		—			—			250,000			—		—			250,000
SPPC Series T	3.375	%	2023	250,000			—		—			250,000			—			—		—			—
Variable Rate Debt (Secured by General and Refunding Mortgage Securities)
NPC IDRB Series 2000A			2020	—			—		—			—			98,100			—		98,100			—
NPC PCRB Series 2006			2036	37,700			—		37,700			—			37,700			—		37,700			—
NPC PCRB Series 2006A			2032	37,975			—		37,975			—			37,975			—		37,975			—
SPPC PCRB Series 2006A			2031	58,200			—		—			58,200			58,200			—		—			58,200
SPPC PCRB Series 2006B			2036	75,000			—		—			75,000			75,000			—		—			75,000
SPPC PCRB Series 2006C			2036	81,475			—		—			81,475			81,475			—		—			81,475
Senior Notes
NVE Senior Notes	6.250	%	2020	315,000			315,000		—			—			315,000			315,000		—			—
NVE Term Loan	2.560	%	2014	195,000			195,000		—			—			195,000			195,000		—			—
Obligations under capital leases				38,415			—		36,571			1,844			44,258			—		42,908			1,350
Unamortized bond premium and discount (net)				759			—		(9,080		)	9,839			1,631			—		(9,827		)	11,458
Current maturities				(129,457		)	—		(129,186		)	(271		)	(356,283		)	—		(106,048		)	(250,235		)
Total Long-Term Debt				$	4,791,809		$	510,000	$	3,103,980		$	1,177,829		$	4,669,798		$	510,000	$	3,230,808		$	928,990

Substantially all utility plant is subject to the liens of the NPC Indenture and the SPPC Indenture under which their respective General and Refunding Mortgage Securities are issued.

Financing Transactions

Nevada Power Company

 In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A.  In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.  

Sierra Pacific Power Company

In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand, to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013.

XML

REGULATORY ACTIONS, Summary of Regulatory Actions (Details) (USD $)	3 Months Ended			9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012	Sep. 30, 2013		Sep. 30, 2012
Energy And Gas Related Regulatory Filings [Abstract]
Regulatory Disallowances	$ 17,335,000		$ 0	$ 17,335,000		$ 0
Nevada Power Company
Revenue Requirement Subject To Change:
Authorized Revenue Requirement	58,000,000			58,000,000
Present Revenue Requirement	117,500,000			117,500,000
$ Change in Revenue Requirement	(59,500,000)			(59,500,000)
Energy And Gas Related Regulatory Filings [Abstract]
Regulatory Disallowances	11,866,000		0	11,866,000		0
Nevada Power Company | DEAA [Member]
Energy And Gas Related Regulatory Filings [Abstract]
Regulatory Disallowances	1,100,000			1,100,000
Nevada Power Company | REPR [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[1]
Authorized Revenue Requirement	28,400,000	[1]		28,400,000	[1]
Present Revenue Requirement	38,700,000	[1]		38,700,000	[1]
$ Change in Revenue Requirement	(10,300,000)	[1]		(10,300,000)	[1]
Nevada Power Company | TRED [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[1]
Authorized Revenue Requirement	15,700,000	[1]		15,700,000	[1]
Present Revenue Requirement	15,900,000	[1]		15,900,000	[1]
$ Change in Revenue Requirement	(200,000)	[1]		(200,000)	[1]
Nevada Power Company | EEPR Base [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[1]
Authorized Revenue Requirement	45,900,000	[1]		45,900,000	[1]
Present Revenue Requirement	32,600,000	[1]		32,600,000	[1]
$ Change in Revenue Requirement	13,300,000	[1]		13,300,000	[1]
Nevada Power Company | EEPR Amortization [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[1]
Authorized Revenue Requirement	(29,900,000)	[1]		(29,900,000)	[1]
Present Revenue Requirement	9,000,000	[1]		9,000,000	[1]
$ Change in Revenue Requirement	(38,900,000)	[1]		(38,900,000)	[1]
Nevada Power Company | EEIR Base [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[2]
Authorized Revenue Requirement	15,100,000	[2]		15,100,000	[2]
Present Revenue Requirement	10,600,000	[2]		10,600,000	[2]
$ Change in Revenue Requirement	4,500,000	[2]		4,500,000	[2]
Nevada Power Company | EEIR Amortization [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[3]
Authorized Revenue Requirement	(17,200,000)	[3]		(17,200,000)	[3]
Present Revenue Requirement	10,700,000	[3]		10,700,000	[3]
$ Change in Revenue Requirement	(27,900,000)	[3]		(27,900,000)	[3]
Energy And Gas Related Regulatory Filings [Abstract]
Regulatory Disallowances	10,800,000			10,800,000
Regulatory reserve	11,200,000			11,200,000
Sierra Pacific Power Company
Energy And Gas Related Regulatory Filings [Abstract]
Regulatory Disallowances	5,469,000		0	5,469,000		0
SPPC Electric
Energy And Gas Related Regulatory Filings [Abstract]
Regulatory Disallowances	5,469,000			5,469,000
SPPC Electric | GRC [Member]
Revenue Requirement Subject To Change:
Effective Date				January 1, 2014
SPPC Electric | Sierra Pacific Power Company
Revenue Requirement Subject To Change:
Authorized Revenue Requirement	55,400,000			55,400,000
Present Revenue Requirement	64,700,000			64,700,000
$ Change in Revenue Requirement	(9,300,000)			(9,300,000)
SPPC Electric | Sierra Pacific Power Company | DEAA [Member]
Energy And Gas Related Regulatory Filings [Abstract]
Regulatory Disallowances	100,000			100,000
SPPC Electric | Sierra Pacific Power Company | REPR [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[1]
Authorized Revenue Requirement	42,300,000	[1]		42,300,000	[1]
Present Revenue Requirement	44,400,000	[1]		44,400,000	[1]
$ Change in Revenue Requirement	(2,100,000)	[1]		(2,100,000)	[1]
SPPC Electric | Sierra Pacific Power Company | TRED [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[1]
Authorized Revenue Requirement	7,400,000	[1]		7,400,000	[1]
Present Revenue Requirement	6,300,000	[1]		6,300,000	[1]
$ Change in Revenue Requirement	1,100,000	[1]		1,100,000	[1]
SPPC Electric | Sierra Pacific Power Company | EEPR Base [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[1]
Authorized Revenue Requirement	6,000,000	[1]		6,000,000	[1]
Present Revenue Requirement	5,600,000	[1]		5,600,000	[1]
$ Change in Revenue Requirement	400,000	[1]		400,000	[1]
SPPC Electric | Sierra Pacific Power Company | EEPR Amortization [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[1]
Authorized Revenue Requirement	(2,100,000)	[1]		(2,100,000)	[1]
Present Revenue Requirement	1,800,000	[1]		1,800,000	[1]
$ Change in Revenue Requirement	(3,900,000)	[1]		(3,900,000)	[1]
SPPC Electric | Sierra Pacific Power Company | EEIR Base [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[4]
Authorized Revenue Requirement	5,500,000	[4]		5,500,000	[4]
Present Revenue Requirement	4,700,000	[4]		4,700,000	[4]
$ Change in Revenue Requirement	800,000	[4]		800,000	[4]
SPPC Electric | Sierra Pacific Power Company | EEIR Amortization [Member]
Revenue Requirement Subject To Change:
Effective Date				Oct. 2013	[3]
Authorized Revenue Requirement	(3,700,000)	[3]		(3,700,000)	[3]
Present Revenue Requirement	1,900,000	[3]		1,900,000	[3]
$ Change in Revenue Requirement	(5,600,000)	[3]		(5,600,000)	[3]
Energy And Gas Related Regulatory Filings [Abstract]
Regulatory Disallowances	5,500,000			5,500,000
Regulatory reserve	4,000,000			4,000,000
SPPC Gas
Revenue Requirement Subject To Change:
$ Change in Revenue Requirement	$ (200,000)			$ (200,000)
SPPC Gas | GRC [Member]
Revenue Requirement Subject To Change:
Effective Date				January 1, 2014

[1] Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income.

[2] The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if NPC earns in excess of its authorized ROR. In future periods, NPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

[3] Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.

[4] The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if SPPC earns in excess of its authorized ROR. In future periods, SPPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

XML

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES     

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 $4 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs.  The site is under contract for sale to a third party and the sale is expected to close in the fourth quarter of 2013.   The sale will not be material to NPC.

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 1-4, with the interest of CDWR in Unit 4 having been terminated in October 2013.  The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant.  NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request.  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.

    NPC and SPPC

NVision and SB 123

NVision is a comprehensive plan of NVE for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and other electric generating plants.  NVision includes the following significant details:

• Accelerating the plan to retire 800 MWs of coal plants, starting as soon as December 31, 2014;

• Replacement of such coal plants with the procurement of 300 MWs from renewable facilities;

• Construction or acquisition and ownership of 50 MWs of electric generating capacity from renewable facilities;

• Construction or acquisition and ownership of 550 MWs of electric generating capacity from other electric generating plants; and

• Assuring regulatory procedures that protect reliability and supply and address financial impacts on customer and utility.

In June 2013, the Nevada State Legislature passed SB 123, which was supported by NVE as part of its NVision initiative and includes the requirements as outlined in the bullets above.  The Utilities, along with other interested parties, are currently working with the PUCN to finalize the rulemaking associated with this bill and expect to file an emissions reduction plan in 2014 to specifically address the plan details as outlined above.

Greenhouse Gas/Carbon Regulations

In conjunction with the release of President Obama’s Climate Action Plan on June 25, 2013, the President issued a memorandum directing the EPA to take several actions on carbon emissions standards for power plants.  As discussed above, NVision and the passage of SB 123, will yield substantial reductions in carbon as NVE and the Utilities retire their existing coal-fired generating facilities on an accelerated schedule. While the Utilities currently cannot predict the financial impact or final mandates by President Obama’s Climate Action Plan or the EPA’s final rules, NVE and the Utilities remain committed to taking progressive steps over time to limit the carbon emissions from its generation fleet by retiring older fossil units and replacing them with new, lower emissions and/or zero emission sources. 

Regional Haze Rules 

In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.

In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations.  In March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station.  The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015.  In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station units at a later date.  In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP.  For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice.  Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015. On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline for the Reid Gardner Generating Station retrofits so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada.  On March 26, 2013, the EPA granted reconsideration of the compliance date for the BART retrofits for Units 1, 2 and 3 at Reid Gardner Generating Station, proposing to extend the compliance date by 18 months, from January 1, 2015 to June 30, 2016. The EPA held a public hearing on April 29, 2013, to accept written and oral comments on this proposed action and t he comment period for this action closed on May 30, 2013. In August 2013, the EPA announced it was taking final action to extend the date by which Units 1, 2, and 3 at Reid Gardner Generating Station must meet the BART limits to reduce emissions of nitrogen oxides. The final date is now affirmed as June 30, 2016.

NVE continues to work toward finalizing the retrofit designs for the affected BART units.  NVE has received approval from the PUCN 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.  As previously disclosed, NVE and the Utilities intend to file with the PUCN their emissions reduction plan in 2014 detailing how they will address the phased retirement of coal fired assets as required under SB 123.  While the BART requirements specify the installation of SNCR’s on Reid Gardner Generating Station Units 1, 2 and 3, the passage of SB 123 could result in the early retirement of those units prior to the required BART installation deadline, pending the final approval of the PUCN.  Therefore, in 2014, NVE and the Utilities will file an emissions reduction plan. NVE and the Utilities would need to obtain either the PUCN approval to retire those units as soon as the end of 2014 or seek approval for the BART retrofit installation with an alternate retirement date.  Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, including Reid Gardner Generating Station Units 1, 2 and 3, but excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units.  NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.

Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal.  In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule.  NVE has intervened in that lawsuit.  In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station.  NVE has intervened in this lawsuit.  At this time management is unable to determine the likelihood of success by petitioners in these litigation matters.  An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned. 

The Navajo Generating Station is also an affected unit under EPA’s Regional Haze Rules. On January 17, 2013, the EPA announced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline for reducing NOx emissions. NVE, along with the other owners of the facility, have been reviewing the EPA proposal to determine its impact on the viability of the plant’s future operations. The land lease for the Navajo Generating Station is up for renewal in 2019.  Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations.  It is believed that the EPA BART proposal will require an investment of up to $1.1 billion in additional emission controls at the plant of which NPC’s ownership share is 11.3%.

The original comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested and was granted several extensions, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners. 

On September 25, 2013, the EPA issued a supplemental proposal which included a BART alternative called the Technical Work Group (“TWG”) Alternative. The TWG Alternative is based upon the proposal submitted to the EPA in July 2013 by a group of Navajo Generating Station stakeholders called the TWG. At this time, the EPA is concurrently accepting comments on the BART determination and the EPA Alternative which were proposed in February 2013, as well the TWG Alternative proposed in the supplemental proposal. Comments are now due by January 6, 2014.

Given the uncertainties that remain regarding the various lease and agreement renewal terms, the timeline for BART installation, and the fact that the EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predict at this time the ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take. As a result of the passage of NVision and these uncertainties, NPC expects to file in 2014 an emissions reduction plan to specifically address its ownership participation in the Navajo Generating Station.

Mercury and Air Toxics Standards (MATS)

In December 2011, the EPA signed for publication in the Federal Register a 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 final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia.  The Court has established a schedule for the litigation; however, the Utilities cannot predict the outcome at this time.

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 will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC.  Note that the actual cost will be dependent upon final engineering design.

The three units at the Navajo Generating Station are also subject to MATS. The plant operator intends to file a one year extension request associated with the compliance date in order to allow for additional testing of various mercury control strategies.  Due to the uncertainty of what control equipment will be ultimately required to control mercury from the Navajo Generating Station units, a cost estimate is unable to be determined at this time.

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.

Other Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.  In addition, NVE and the Utilities may also be subject to future state or federal regulations.  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, which may be accelerated by any decision to retire a generating station or other facility.  If remediation activities involve statutory joint and several liability provisions, strict liability or cost recovery of 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 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.

In 2008, NPC signed an Administrative Order of Consent (AOC) as owner and operator of Reid Gardner Generating Station Units 1, 2 and 3 and as co-owner and operating agent of Unit 4.  In October 2013, NPC purchased Unit 4 from CDWR. Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs.  However, actual costs of work under the AOC may vary significantly once the scope of work is defined and additional site characterization has been completed.

NVE and the Utilities seek to continually comply with environmental regulations; however, given the uncertainties involved in the federal, state and local regulatory environment, future costs to comply may be material.

Litigation Contingencies

NVE

Litigation Related to the MidAmerican Merger

Following the announcement of the proposed acquisition of NVE by MEHC through its subsidiary Silver Merger Sub, Inc. on May 29, 2013, several complaints were filed by alleged NVE shareholders in the Eighth Judicial District Court in Clark County, Nevada, challenging the MidAmerican Merger.

On June 6, 2013, a complaint was filed on behalf of a putative class of NVE public shareholders, naming NVE, its BOD, and Silver Merger Sub, Inc., as defendants. This complaint was amended on July 16, 2013.  The amended complaint generally alleges that the individual defendants breached their fiduciary duties in connection with the proposed MidAmerican Merger, including by approving the transaction on allegedly unfair terms, at an allegedly unfair price and pursuant to an allegedly inadequate process; allegedly acting with conflicts and in their own personal interests rather than those of shareholders; and making inadequate disclosures in connection with requested shareholder approval of the proposed MidAmerican Merger.  The amended complaint also alleges that Silver Merger Sub. Inc., NVE and MEHC aided and abetted the individual defendants in breaching their fiduciary duties. 

Four additional complaints were filed in the Eighth Judicial District Court in Clark County, Nevada on June 7, 2013, June 10, 2013, July 12, 2013 and August 16, 2013.  These complaints contain claims and allegations similar to the amended July 16, 2013 complaint and seek similar relief on behalf of the same putative class. Onecomplaint was voluntarily dismissed. The remaining cases were consolidated in Department XI of the Eighth Judicial District Court in Clark County, Nevada.

An agreement-in-principle has been reached between the parties to these lawsuits, which was memorialized in a memorandum of understanding executed on September 4, 2013.  The memorandum of understanding called for NVE to supplement the proxy statement for the special meeting of stockholders related to the MidAmerican Merger, and the supplemental information was in fact provided via NVE’s Form 8-K dated September 9, 2013. The parties currently are preparing a final stipulation of settlement which will be submitted to the court for approval. It is not known at this time when the court will set hearings and/or issue a final order, but NVE does not expect the outcome of this litigation or settlement to delay the closing of the MidAmerican Merger or otherwise have a material impact on NVE.

NPC 

Peabody Western Coal Company - Royalty Claim

NPC owns an 11% interest in the Navajo Generating Station, which is located in northern Arizona and 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 June 1999, the Navajo Nation filed suit against Salt River, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”).  NPC was 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 asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process.  The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.

In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit.  In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible re-filing.

In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement among the Navajo Nation, Peabody, Salt River and SCE.  At the request of Salt River, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station. 

SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station.  In October 2013, NPC settled with SCE on this matter.  The terms of the settlement are not material to NPC.

November 2005 Land Investors

In 2006, November 2005 Land Investors, LLC (“NLI”) purchased from the U.S. through the Bureau of Land Management (“BLM”) 2,675 acres of land located in North Las Vegas, Nevada. A small portion of the land was and is traversed by a 500kV transmission line owned by NPC and sited pursuant to a pre-existing right-of-way grant (“Grant”) from the BLM. Subsequent to NLI’s purchase, a dispute arose as to whether NPC owed rent and, if it did, the amount owed to NLI under the Grant. NLI eventually “terminated” the Grant and brought claims against NPC for breach of contract, inverse condemnation and trespass. NPC counterclaimed for express condemnation of a perpetual easement over the right-of-way corridor. The matter proceeded to trial in the Eighth Judicial District Court, Clark County, Nevada. In September 2013, the court awarded NLI approximately $1.0 million for unpaid rent and $5.1 million for inverse condemnation, plus interest and attorneys’ fees. The court also found NPC was entitled to judgment in its favor on its counterclaim for condemnation of the right-of-way corridor.

NPC has appealed to the Nevada Supreme Court, which has yet to establish a schedule for the appeal. Management cannot assess or predict the outcome of the case at this time, but it is not expected to be material to NPC.

SPPC

Farad Dam

In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million.  One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume.  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.  The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.

SPPC filed a claim with the Farad Dam’s insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers.  The insurers contested the extent and amount of insurance coverage.  Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.

In July 2012, the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC’s right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost.  In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three years time to rebuild to start at the conclusion of all litigation.

The District Court has now set the briefing schedule for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC.

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 Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE’s future lease payments are adjusted for final capital costs, for which the Utilities expect to get regulatory recovery. 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, as of September 30, 2013, capitalized construction costs associated with GBT’s 75% interest of $370.8 million and $19.4 million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.

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REGULATORY ACTIONS

9 Months Ended

Sep. 30, 2013

REGULATORY ACTIONS [Abstract]

REGULATORY ACTIONS

REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy amounts were included in the consolidated balance sheets as of September 30, 2013 (dollars in thousands):

	September 30, 2013
	NVE Total			NPC Electric			SPPC Electric			SPPC Gas
Deferred Energy
Cumulative Deferred Balance authorized in 2013 DEAA	$	(152,990	)	$	(102,227	)	$	(32,693	)	$	(18,070	)
2013 Amortization	111,977			69,288			23,695			18,994
2013 Deferred Energy Under Collections (1)	118,397			95,465			19,697			3,235
Deferred Energy Balance at September 30, 2013 - Subtotal	$	77,384		$	62,526		$	10,699		$	4,159
Reinstatement of deferred energy (effective 6/07, 10 years)	89,906			89,906			—			—
Total Deferred Energy	$	167,290		$	152,432		$	10,699		$	4,159
Current Assets
Deferred energy	$	82,235		$	68,391		$	10,322		$	3,522
Non-current Assets
Deferred energy	85,055			84,041			377			637
Total Net Deferred Energy	$	167,290		$	152,432		$	10,699		$	4,159

⁽¹⁾  These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting Policies, Deferred Energy Accounting, of the Notes to the Financial Statements in the 2012 Form 10-K.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Joint Application for the merger between NVE and MEHC (MidAmerican Merger)

In July 2013, NVE and MEHC filed a joint application with the PUCN seeking the authorization of the MidAmerican Merger. Under Nevada law, the PUCN may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “in the public interest”.  If the PUCN does not issue a final order regarding the MidAmerican Merger within 180 days of the application filing date, the transaction will be deemed to be authorized.  Based on the date of filing, the expected authorization date for the joint application between NVE and MEHC is January 2014.  Hearings are scheduled for November 2013.

Joint Application of NPC and SPPC (One Company Merger Filing)

                In May 2013, NPC and SPPC filed a joint application with the PUCN to consolidate the Utilities into a single jurisdictional utility.  The joint application with the PUCN requested the following:

• Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC’s assets and obligations to NPC, and renaming the surviving utility NVEOC;

• Authority to transfer SPPC’s certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC’s CPCN to reflect the name of the surviving utility, NVEOC; and

• Authority to transfer all SPPC’s electric and gas utility assets, including electric generation assets, to NPC.

The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.”  The PUCN is not bound by any statutory deadlines with respect to this application. Hearings were expected to begin in February 2014, but the Utilities are seeking to delay the proceedings to the second half of 2014. 

Financing Application

                Concurrent with the One Company Merger filing, NPC and SPPC filed a joint financing application with the PUCN.  The application requested the PUCN to restate and review the Utilities’ existing unused authority and to assign and consolidate the unused authority under NVEOC.  In addition, the application requests new authority of $705.0 million.  The consolidated authority would give NVEOC authority to issue new debt of $1.1 billion and authority to refinance or redeem debt of $1.5 billion. The application does not seek a change to NPC’s and SPPC’s existing revolving credit facility authority of $1.3 billion and $600 million, respectively.   The Utilities have requested that the financing application be consolidated with the One Company Merger filing.  However, as the One Company Merger will not be approved prior to the December 31, 2013 expiration of NPC’s current financing authority, NPC requested that its current authority be extended, as well as additional authority to refinance debt of $255 million.  In September 2013, the PUCN accepted a stipulation extending NPC’s existing financing authority until an order is issued in the One Company Merger filing.

Nevada Power Company

NPC 2013 DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEIR and EEPR rate elements.  In September 2013, the PUCN issued an order disallowing approximately $1.1 million (pre-tax) in deferred energy costs, which NPC expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013 and correspondingly adjusted the deferred energy balance as reflected in the table above. In addition, the PUCN indicated in their order that EEIR revenue should not contribute to the Utilities earning more than their authorized ROR. As NPC earned in excess of its authorized ROR in 2012, the PUCN disallowed approximately $10.8 million in pre-tax EEIR revenues (including carrying charges) which was expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013. Furthermore, as a result of this order and NPC’s estimated 2013 ROR calculated to be in excess of its authorized ROR, NPC has recorded a provision for refund of $11.2 million pre-tax against operating revenues, representing all EEIR revenues recorded during the nine months ended September 30, 2013. The September PUCN order includes the following changes in revenue requirement (dollars in millions):

	Effective Date	Authorized Revenue Requirement			Present Revenue Requirement		$ Change in Revenue Requirement
Revenue Requirement Subject To Change:
REPR (1)	Oct. 2013	$	28.4		$	38.7	$	(10.3	)
TRED (1)	Oct. 2013	15.7			15.9		(0.2		)
EEPR Base (1)	Oct. 2013	45.9			32.6		13.3
EEPR Amortization (1)	Oct. 2013	(29.9		)	9.0		(38.9		)
EEIR Base (2)	Oct. 2013	15.1			10.6		4.5
EEIR Amortization (3)	Oct. 2013	(17.2		)	10.7		(27.9		)
Total Revenue Requirement		$	58.0		$	117.5	$	(59.5	)

⁽¹⁾  Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income.

⁽²⁾  The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if NPC earns in excess of its authorized ROR. In future periods, NPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

⁽³⁾  Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.

Sierra Pacific Power Company

  SPPC Electric General Rate Case

In June 2013, SPPC filed its statutorily required GRC for its Nevada electric operations and updated the filing in August 2013.  In the updated filing, SPPC is requesting the following:

• Decrease in general rates by $4.7 million, approximately a 0.7% decrease; and

• ROE and ROR of 10.4% and 7.74%, respectively.

Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014. 

SPPC Gas General Rate Case

In June 2013, SPPC filed a GRC for its gas operations and updated the filing in August 2013.  In the updated filing, SPPC is requesting the following:

• Increase in general rates by $6.0 million, approximately a 6.1% increase; and

• ROE and ROR of 10.35% and 7.72%, respectively.

Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014.

SPPC 2013 Electric DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEPR and EEIR rate elements. In September 2013, the PUCN issued an order disallowing approximately $0.1 million (pre-tax) in deferred energy costs, which SPPC expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013 and correspondingly adjusted the deferred energy balance as reflected in the table above. In addition, with respect to the EEIR disallowance discussed above under NPC, the PUCN disallowed $5.5 million (pre-tax) of SPPC's 2012 EEIR revenues, (including carrying charges) as a result of earning in excess of its authorized ROR. As a result $5.5 million was expensed as a regulatory disallowance for the three and nine months ended September 30, 2013. Also, similar to NPC, SPPC’s estimated 2013 ROR is calculated to be in excess of its authorized ROR, as such, SPPC has recorded a provision for refund of $4.0 million pre-tax against operating revenues, representing all EEIR revenues recorded during the nine months ended September 30, 2013. The September PUCN order includes the following changes in revenue requirement (dollars in millions):

	Effective Date	Authorized Revenue Requirement			Present Revenue Requirement		$ Change in Revenue Requirement
Revenue Requirement Subject To Change:
REPR (1)	Oct. 2013	$	42.3		$	44.4	$	(2.1	)
TRED (1)	Oct. 2013	7.4			6.3		1.1
EEPR Base (1)	Oct. 2013	6.0			5.6		0.4
EEPR Amortization (1)	Oct. 2013	(2.1		)	1.8		(3.9		)
EEIR Base (2)	Oct. 2013	5.5			4.7		0.8
EEIR Amortization (3)	Oct. 2013	(3.7		)	1.9		(5.6		)
Total Revenue Requirement		$	55.4		$	64.7	$	(9.3	)

⁽¹⁾ Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income.

⁽²⁾ The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if SPPC earns in excess of its authorized ROR. In future periods, SPPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

⁽³⁾ Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.

SPPC 2013 Nevada Gas DEAA and REPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ended December 31, 2012 and to reset the REPR.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above.  In September 2013, the PUCN issued an order resulting in an overall decrease in revenue requirement of $0.2 million.

FERC Matters

NPC

NPC 2012 FERC Transmission Rate Case

In October 2012, NPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2003.  In December 2012, FERC issued an order which suspended the proposed rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013.  All rates are currently subject to refund and final approval by the FERC.  However, at this time management is unable to determine the final revenue impact of the case.

SPPC

SPPC 2012 FERC Transmission Rate Case

In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003, respectively.  In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013. On June 17, 2013, SPPC filed an unopposed settlement agreement resolving all issues with the FERC, for approval for rates effective June 1, 2013.    FERC approved the settlement on August 29, 2013. The rate changes under the terms of the settlement agreement are expected to result in an overall annual revenue increase of $1.5 million.

NVE, NPC and SPPC

2013 FERC Transmission Rate Case

In May 2013, NPC and SPPC filed an application with the FERC to reset transmission and ancillary service rates effective on the later of January 1, 2014, or the ON Line in-service date.  The rate changes reflect the addition of the ON Line in the transmission revenue requirement.  Various intervenors filed protests and NPC and SPPC filed a response to those protests on July 16, 2013.  On August 5, 2013, FERC issued an order which suspended the rate changes until January 1, 2014 or the in-service date for ON Line, subject to refund. On August 12, 2013 the FERC designated a Settlement Judge and the matter is now in settlement proceedings.  At this time, management is unable to determine the final revenue impact of the case.

FERC One Company Merger Request

In May 2013, NVE, NPC and SPPC filed an application with the FERC under Section 203 of the Federal Power Act for Approval of Internal Reorganization.  In their request, NPC and SPPC requested FERC authorization for an internal corporate reorganization under which SPPC will merge into NPC and the surviving entity will be renamed NVEOC.  On October 21, 2013, NVE, NPC and SPPC submitted an informational filing with FERC indicating that given the status of an application pending before the PUCN, the applicants did not object to FERC deferring its consideration of the application. The application remains pending before FERC for consideration.  

FERC MidAmerican Merger Request

On July 12, 2013, an application was filed with the FERC under Section 203 of the Federal Power Act, to approve the MidAmerican Merger.  The MidAmerican Merger is discussed in more detail in Note 2, Merger-Related Activities.   Under Section 203 of the Federal Power Act, the FERC may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “consistent with the public interest”.  If the FERC does not grant or deny the application within 180 days after the application was filed, the application is deemed granted unless the FERC finds that further consideration, for a period not to exceed an additional 180 days, is required to determine whether the transaction meets the specified standards.  The application requests authorization of the proposed transaction by December 19, 2013; however, NVE is unable to determine the timing of a decision in the filing.

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $) In Thousands, except Share data	Total	Common Stock	Treasury stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Nevada Power Company	Nevada Power Company Common Stock	Nevada Power Company Additional Paid-in Capital	Nevada Power Company Retained Earnings	Nevada Power Company Accumulated Other Comprehensive Income (Loss)	Sierra Pacific Power Company	Sierra Pacific Power Company Common Stock	Sierra Pacific Power Company Additional Paid-in Capital	Sierra Pacific Power Company Retained Earnings	Sierra Pacific Power Company Accumulated Other Comprehensive Income (Loss)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2011	$ 3,406,079	$ 236,000	$ 0	$ 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	0					1,000					1,000
Net Income	304,782				304,782		256,151			256,151		65,750			65,750
Change in compensation retirement benefits liability and amortization	464					464	192				192	127				127
Change in market value of risk management assets and liabilities	(668)					(668)
Unrealized net gain/(loss) on investment	0
Common stock repurchased	(4,509)		(4,509)
Common stock repurchased (shares)			(252,000)
Dividends Declared	(110,920)				(110,920)		(119,000)			(119,000)		(20,000)			(20,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2012	3,595,228	236,000	(4,509)	2,713,736	658,139	(8,138)	2,986,320	1	2,308,219	682,025	(3,925)	1,020,419	4	1,111,262	(89,590)	(1,257)
Balance (in shares) at Sep. 30, 2012		235,999,750	(252,000)					1,000					1,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Jun. 30, 2012
Net Income	223,170						195,170					34,427
Change in compensation retirement benefits liability and amortization	155						65					42
Change in market value of risk management assets and liabilities	(193)
Unrealized net gain/(loss) on investment	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2012	3,595,228	236,000		2,713,736			2,986,320	1	2,308,219			1,020,419	4	1,111,262
Balance (in shares) at Sep. 30, 2012		235,999,750						1,000					1,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2012	3,557,371	236,000	(16,804)	2,712,943	635,303	(10,071)	2,922,318	1	2,308,211	618,612	(4,506)	1,038,736	4	1,111,266	(70,986)	(1,548)
Balance (in shares) at Dec. 31, 2012	235,079,156	235,999,750	(920,594)				1,000	1,000				1,000	1,000
Net Income	271,942				271,942		228,552			228,552		61,931			61,931
Employee Benefits	18,603		15,235	3,368
Dividend Reinvestment and Employee Benefits (in shares)			827,097
Change in compensation retirement benefits liability and amortization	738					738	290				290	176				176
Change in market value of risk management assets and liabilities	485					485
Unrealized net gain/(loss) on investment	33					33
Common stock repurchased	(6,329)		(6,329)
Common stock repurchased (shares)			(325,178)
Dividends Declared	(134,250)				(134,250)		(105,000)			(105,000)		(40,000)			(40,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2013	3,708,593	236,000	(7,898)	2,716,311	772,995	(8,815)	3,046,160	1	2,308,211	742,164	(4,216)	1,060,843	4	1,111,266	(49,055)	(1,372)
Balance (in shares) at Sep. 30, 2013	235,581,074	235,999,750	(418,675)				1,000	1,000				1,000	1,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Jun. 30, 2013
Net Income	187,234						164,442					29,251
Change in compensation retirement benefits liability and amortization	246						96					59
Change in market value of risk management assets and liabilities	(11)
Unrealized net gain/(loss) on investment	98
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Sep. 30, 2013	$ 3,708,593	$ 236,000					$ 3,046,160	$ 1	$ 2,308,211			$ 1,060,843	$ 4	$ 1,111,266
Balance (in shares) at Sep. 30, 2013	235,581,074	235,999,750					1,000	1,000				1,000	1,000

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LONG-TERM DEBT, Debt Instruments (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	$ (759,000)	$ (1,631,000)
Current maturities	(129,457,000)	(356,283,000)
Total Long-Term Debt	4,791,809,000	4,669,798,000
Secured, General and Refunding Mortgage Securities, NPC Series L [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000,000	250,000,000
Stated interest rate (in hundredths)	5.875%
Maturity date	2015
Secured, General and Refunding Mortgage Securities, NPC Series M [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	210,000,000	210,000,000
Stated interest rate (in hundredths)	5.95%
Maturity date	2016
Secured, General and Refunding Mortgage Securities, NPC Series N [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	370,000,000	370,000,000
Stated interest rate (in hundredths)	6.65%
Maturity date	2036
Secured, General and Refunding Mortgage Securities, NPC Series O [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	325,000,000	325,000,000
Stated interest rate (in hundredths)	6.50%
Maturity date	2018
Secured, General and Refunding Mortgage Securities, NPC Series R [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	350,000,000	350,000,000
Stated interest rate (in hundredths)	6.75%
Maturity date	2037
Secured, General and Refunding Mortgage Securities, NPC Series S [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	500,000,000	500,000,000
Stated interest rate (in hundredths)	6.50%
Maturity date	2018
Secured, General and Refunding Mortgage Securities, Series U [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	125,000,000	125,000,000
Stated interest rate (in hundredths)	7.375%
Maturity date	2014
Secured, General and Refunding Mortgage Securities, Series V [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	500,000,000	500,000,000
Stated interest rate (in hundredths)	7.125%
Maturity date	2019
Secured, General and Refunding Mortgage Securities, Series X [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000,000	250,000,000
Stated interest rate (in hundredths)	5.375%
Maturity date	2040
Secured, General and Refunding Mortgage Securities, Series Y [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000,000	250,000,000
Stated interest rate (in hundredths)	5.45%
Maturity date	2041
Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	450,000,000	450,000,000
Stated interest rate (in hundredths)	6.00%
Maturity date	2016
Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	251,742,000	251,742,000
Stated interest rate (in hundredths)	6.75%
Maturity date	2037
Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	0	250,000,000
Stated interest rate (in hundredths)	5.45%
Maturity date	2013
General and Refunding Mortgage Securities SPPC Series T [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000,000	0
Stated interest rate (in hundredths)	3.375%
Maturity date	2023
Secured Variable Rate Debt Npc Idrb Series Two Thousand [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		98,100,000
Maturity date	2020
Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	37,700,000	37,700,000
Maturity date	2036
Secured Variable Rate Debt Npc Pcrb Series Two Thousand Six [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	37,975,000	37,975,000
Maturity date	2032
Secured Variable Rate Debt Sppc Pcrb Series 2006 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	58,200,000	58,200,000
Maturity date	2031
Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	75,000,000	75,000,000
Maturity date	2036
Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	81,475,000	81,475,000
Maturity date	2036
NVE Senior Notes due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	195,000,000	195,000,000
Stated interest rate (in hundredths)	2.56%
Maturity date	2014
NVE Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	315,000,000	315,000,000
Stated interest rate (in hundredths)	6.25%
Maturity date	2020
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	38,415,000	44,258,000
Parent Company
Debt Instrument [Line Items]
Total Long-Term Debt	510,000,000	510,000,000
Parent Company | NVE Senior Notes due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	195,000,000	195,000,000
Parent Company | NVE Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	315,000,000	315,000,000
Nevada Power Company
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	9,080,000	9,827,000
Current maturities	(129,186,000)	(106,048,000)
Total Long-Term Debt	3,103,980,000	3,230,808,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series L [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000,000	250,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series M [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	210,000,000	210,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series N [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	370,000,000	370,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series O [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	325,000,000	325,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series R [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	350,000,000	350,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, NPC Series S [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	500,000,000	500,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, Series U [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	125,000,000	125,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, Series V [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	500,000,000	500,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, Series X [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000,000	250,000,000
Nevada Power Company | Secured, General and Refunding Mortgage Securities, Series Y [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000,000	250,000,000
Nevada Power Company | Secured Variable Rate Debt Npc Idrb Series Two Thousand [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		98,100,000
Notice Of Redemption	100,000,000
Notice Of Redemption Date	July 1, 2013
Redemption Date	August 1, 2013
Redemption Percentage	100.00%
Amount of debt redeemed	98,100,000
Nevada Power Company | Secured Variable Rate Debt, NPC PCRB Series 2006 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	37,700,000	37,700,000
Nevada Power Company | Secured Variable Rate Debt Npc Pcrb Series Two Thousand Six [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	37,975,000	37,975,000
Nevada Power Company | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	36,571,000	42,908,000
Sierra Pacific Power Company
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	(9,839,000)	(11,458,000)
Current maturities	(271,000)	(250,235,000)
Total Long-Term Debt	1,177,829,000	928,990,000
Sierra Pacific Power Company | Secured, General and Refunding Mortgage Securities, SPPC Series M [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	450,000,000	450,000,000
Sierra Pacific Power Company | Secured, General and Refunding Mortgage Securities, SPPC Series P [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	251,742,000	251,742,000
Sierra Pacific Power Company | Secured, General and Refunding Mortgage Securities, SPPC Series Q [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	0	250,000,000
Redemption Date	September 1, 2013
Amount of debt redeemed	250,000,000
Sierra Pacific Power Company | General and Refunding Mortgage Securities SPPC Series T [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	250,000,000	0
Net Proceeds used to redeem debt	247,900,000
Debt Instrument, Issuance Date	Aug. 01, 2013
Sierra Pacific Power Company | Secured Variable Rate Debt Sppc Pcrb Series 2006 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	58,200,000	58,200,000
Sierra Pacific Power Company | Secured Variable Rate Debt Sppc Pcrb Series 2006 B [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	75,000,000	75,000,000
Sierra Pacific Power Company | Secured Variable Rate Debt Sppc Pcrb Series 2006 C [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	81,475,000	81,475,000
Sierra Pacific Power Company | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 1,844,000	$ 1,350,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2013

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 Company, Inc. and Sierra Gas Holding Company.  All intercompany balances and 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.

In the opinion of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown.  These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in the 2012 Form 10-K.

The results of operations and cash flows of NVE, NPC and SPPC for the nine months ended September 30, 2013, are not necessarily indicative of the results to be expected for the full year.

Variable Interest Entities

Consolidations of VIEs

To identify potential variable interests, management reviewed 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 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 September 30, 2013, 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.

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

Recent Accounting Standards Update

Derivatives and Hedging (ASC815) 

In July 2013, the FASB amended its existing guidance related to hedge accounting.  The amendment permits the Fed Funds Effective Swap Rate (OIS) to be used as a U.S benchmark interest rate for hedge accounting purposes under ASC 815, in addition, to the current approved U.S. rates which include interest rates on direct Treasury obligations of the U.S. government (UST) and LIBOR.  The amendment is effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013.    The adoption of this guidance did not have an impact on the presentation of the consolidated financial statements or disclosure requirements for NVE and the Utilities.

Income Taxes (ASC 740)

In July 2013, the FASB amended its existing guidance related to the presentation of an unrecognized tax benefit on the financial statements.  ASC 740, Income Taxes, does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a NOL carryforward, a similar tax loss, or a tax credit carryforward exists.  As a result, there is diversity in practice in the presentation of unrecognized tax benefits.  The objective of the amendment is to eliminate the diversity in practice, requiring the unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward with certain exceptions.  The amendment can be applied prospectively or retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 for public entities.  NVE and the Utilities have elected to early adopt this amendment prospectively as of September 30, 2013, presenting their unrecognized tax benefit as a reduction to their NOL deferred tax asset. The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.

Federal Income Tax Regulations

In September 2013, the Internal Revenue Service and the U.S. Treasury Department released final tax regulations on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014.  NVE and the Utilities continue to evaluate the effects of the tangible property regulations as well as the generation guidance in Revenue Procedure 2013-24, but do not believe that these tax regulations will have a material impact on the presentation of the financial statements for NVE and the Utilities.

Other Comprehensive Income (ASC 220)

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.  In February 2013, the FASB reinstated certain portions of the deferred amendment.  The reinstated amendment is applied prospectively and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance did not have an impact on the presentation of the financial statements for NVE and the Utilities.

Balance Sheet Offsetting Disclosures (ASC 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 includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements.  The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance did not have an impact on the disclosure requirements for NVE and the Utilities.

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RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

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 post-retirement 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 post-retirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees. A summary of the components of net periodic pension and other post-retirement costs for the three and nine months ended September 30 follows. This summary is based on a December 31, measurement date (dollars in thousands):

NVE
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	5,132		$	4,406		$	660		$	595
Interest cost	9,303			10,228			1,677			1,905
Expected return on plan assets	(12,708		)	(12,447		)	(1,687		)	(1,563		)
Amortization of prior service cost	(720		)	(724		)	(952		)	(987		)
Amortization of net loss	4,797			3,473			890			731
Net periodic benefit cost	$	5,804		$	4,936		$	588		$	681

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	15,396		$	13,220		$	1,980		$	1,787
Interest cost	27,911			30,684			5,030			5,715
Expected return on plan assets	(38,124		)	(37,341		)	(5,060		)	(4,690		)
Amortization of prior service cost	(2,162		)	(2,173		)	(2,857		)	(2,961		)
Amortization of net loss	14,391			10,418			2,671			2,193
Net periodic benefit cost	$	17,412		$	14,808		$	1,764		$	2,044

The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 34.5% and 35.0% respectively.

NPC
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	2,761		$	2,358		$	389		$	350
Interest cost	4,453			4,881			556			602
Expected return on plan assets	(6,270		)	(6,237		)	(631		)	(592		)
Amortization of prior service cost	(453		)	(456		)	(23		)	229
Amortization of net loss	2,117			1,363			289			221
Net periodic benefit cost	$	2,608		$	1,909		$	580		$	810

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	8,283		$	7,072		$	1,167		$	1,050
Interest cost	13,358			14,643			1,667			1,807
Expected return on plan assets	(18,810		)	(18,711		)	(1,892		)	(1,775		)
Amortization of prior service cost	(1,358		)	(1,367		)	(69		)	687
Amortization of net loss	6,351			4,089			867			662
Net periodic benefit cost	$	7,824		$	5,726		$	1,740		$	2,431

The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.9% and 36.9% respectively.

SPPC
	Pension Benefits						Other Post-Retirement Benefits
	For the Three Months Ended September 30						For the Three Months Ended September 30
	2013			2012			2013			2012
Service cost	$	1,926		$	1,695		$	251		$	227
Interest cost	4,558			5,043			1,104			1,283
Expected return on plan assets	(6,162		)	(5,937		)	(1,022		)	(941		)
Amortization of prior service cost	(277		)	(277		)	(933		)	(1,220		)
Amortization of net loss	2,501			2,026			592			504
Net periodic benefit cost	$	2,546		$	2,550		$	(8	)	$	(147	)

	Pension Benefits						Other Post-Retirement Benefits
	For the Nine Months Ended September 30						For the Nine Months Ended September 30
	2013			2012			2013			2012
Service cost	$	5,778		$	5,086		$	752		$	682
Interest cost	13,676			15,130			3,310			3,848
Expected return on plan assets	(18,486		)	(17,813		)	(3,065		)	(2,823		)
Amortization of prior service cost	(831		)	(831		)	(2,798		)	(3,658		)
Amortization of net loss	7,502			6,078			1,777			1,511
Net periodic benefit cost	$	7,639		$	7,650		$	(24	)	$	(440	)

The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 and was 35.6% and 35.1%, respectively.

As discussed in Note 10, Retirement Plan and Post-Retirement Benefits, of the Notes to Financial Statements in the 2012 Form 10-K, NVE offered a voluntary lump sum pension pay out to former employees not currently of retirement age but eligible for future benefits and certain retiree participants already receiving benefits under NVE’s pension plan in an effort to reduce NVE’s future pension obligation. During the nine months ended September 30, 2013, NVE paid $21.5 million in lump sum pension pay outs from the pension assets. The company does not expect any further material amounts to be paid in 2013.

During the nine months ended September 30, 2013 and 2012, the company made contributions to the pension plan in the amount of $20.0 million and $15.0 million, respectively and $5.0 million and $7.1 million, respectively in contributions to the other post-retirement benefits plan. At the present time, it is not anticipated that additional funding will be required for either plan in 2013 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding. The amounts to be contributed in 2013 may change subject to market conditions.

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LONG-TERM DEBT (Tables)

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Schedule of Long-term Debt

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

				September 30,											December 31,
				2013											2012
Long-Term Debt:	Stated Rate		Maturity Date	Consolidated			NVE Holding Co.		NPC			SPPC			Consolidated			NVE Holding Co.		NPC			SPPC
Secured Debt
General and Refunding Mortgage Securities
NPC Series L	5.875	%	2015	$	250,000		$	—	$	250,000		$	—		$	250,000		$	—	$	250,000		$	—
NPC Series M	5.950	%	2016	210,000			—		210,000			—			210,000			—		210,000			—
NPC Series N	6.650	%	2036	370,000			—		370,000			—			370,000			—		370,000			—
NPC Series O	6.500	%	2018	325,000			—		325,000			—			325,000			—		325,000			—
NPC Series R	6.750	%	2037	350,000			—		350,000			—			350,000			—		350,000			—
NPC Series S	6.500	%	2018	500,000			—		500,000			—			500,000			—		500,000			—
NPC Series U	7.375	%	2014	125,000			—		125,000			—			125,000			—		125,000			—
NPC Series V	7.125	%	2019	500,000			—		500,000			—			500,000			—		500,000			—
NPC Series X	5.375	%	2040	250,000			—		250,000			—			250,000			—		250,000			—
NPC Series Y	5.450	%	2041	250,000			—		250,000			—			250,000			—		250,000			—
SPPC Series M	6.000	%	2016	450,000			—		—			450,000			450,000			—		—			450,000
SPPC Series P	6.750	%	2037	251,742			—		—			251,742			251,742			—		—			251,742
SPPC Series Q	5.450	%	2013	—			—		—			—			250,000			—		—			250,000
SPPC Series T	3.375	%	2023	250,000			—		—			250,000			—			—		—			—
Variable Rate Debt (Secured by General and Refunding Mortgage Securities)
NPC IDRB Series 2000A			2020	—			—		—			—			98,100			—		98,100			—
NPC PCRB Series 2006			2036	37,700			—		37,700			—			37,700			—		37,700			—
NPC PCRB Series 2006A			2032	37,975			—		37,975			—			37,975			—		37,975			—
SPPC PCRB Series 2006A			2031	58,200			—		—			58,200			58,200			—		—			58,200
SPPC PCRB Series 2006B			2036	75,000			—		—			75,000			75,000			—		—			75,000
SPPC PCRB Series 2006C			2036	81,475			—		—			81,475			81,475			—		—			81,475
Senior Notes
NVE Senior Notes	6.250	%	2020	315,000			315,000		—			—			315,000			315,000		—			—
NVE Term Loan	2.560	%	2014	195,000			195,000		—			—			195,000			195,000		—			—
Obligations under capital leases				38,415			—		36,571			1,844			44,258			—		42,908			1,350
Unamortized bond premium and discount (net)				759			—		(9,080		)	9,839			1,631			—		(9,827		)	11,458
Current maturities				(129,457		)	—		(129,186		)	(271		)	(356,283		)	—		(106,048		)	(250,235		)
Total Long-Term Debt				$	4,791,809		$	510,000	$	3,103,980		$	1,177,829		$	4,669,798		$	510,000	$	3,230,808		$	928,990

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SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information

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

Three Months Ended
September 30, 2013
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	1,013,151		$	3		$	786,142		$	227,006		$	213,463		$	13,543
Energy Costs:
Fuel for power generation	217,954			—			163,127			54,827			54,827			—
Purchased power	205,970			—			172,582			33,388			33,388			—
Gas purchased for resale	7,383			—			—			7,383			—			7,383
Deferred energy	(55,270		)	—			(45,381		)	(9,889		)	(7,925		)	(1,964		)
Energy efficiency program costs	16,042			—			13,998			2,044			2,044			—
Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
Total Costs	$	409,414		$	—		$	316,192		$	93,222		$	87,803		$	5,419
Gross Margin	$	603,737		$	3		$	469,950		$	133,784		$	125,660		$	8,124
Merger-related costs	7,857			229			5,620			2,008
Other operating expenses	106,068			830			70,844			34,394
Maintenance	17,176			—			11,208			5,968
Depreciation and amortization	96,801			—			68,849			27,952
Taxes other than income	14,214			57			8,213			5,944
Operating Income (Loss)	$	361,621		$	(1,113	)	$	305,216		$	57,518

Nine Months Ended
September 30, 2013
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	2,329,011		$	10		$	1,695,129		$	633,872		$	560,392		$	73,480
Energy Costs:
Fuel for power generation	554,181			—			412,904			141,277			141,277			—
Purchased power	498,141			—			383,386			114,755			114,755			—
Gas purchased for resale	62,277			—			—			62,277			—			62,277
Deferred energy	(221,022		)	—			(154,484		)	(66,538		)	(44,223		)	(22,315		)
Energy efficiency program costs	38,486			—			32,807			5,679			5,679			—
Regulatory disallowance	17,335			—			11,866			5,469			5,469			—
Total Costs	$	949,398		$	—		$	686,479		$	262,919		$	222,957		$	39,962
Gross Margin	$	1,379,613		$	10		$	1,008,650		$	370,953		$	337,435		$	33,518
Merger-related costs	21,409			1,394			14,487			5,528
Other operating expenses	317,538			2,747			208,336			106,455
Maintenance	66,128			—			45,172			20,956
Depreciation and amortization	291,687			—			207,915			83,772
Taxes other than income	46,536			318			27,804			18,414
Operating Income (Loss)	$	636,315		$	(4,449	)	$	504,936		$	135,828

Three Months Ended
September 30, 2012
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	1,026,488		$	4		$	802,334		$	224,150		$	212,073		$	12,077
Energy Costs:
Fuel for power generation	171,316			—			123,992			47,324			47,324			—
Purchased power	205,686			—			171,687			33,999			33,999			—
Gas purchased for resale	5,382			—			—			5,382			—			5,382
Deferred energy	(29,036		)	—			(22,685		)	(6,351		)	(5,498		)	(853		)
Energy efficiency program costs	32,584			—			28,492			4,092			4,092			—
Total Costs	$	385,932		$	—		$	301,486		$	84,446		$	79,917		$	4,529
Gross Margin	$	640,556		$	4		$	500,848		$	139,704		$	132,156		$	7,548
Other operating expenses	100,108			608			65,372			34,128
Maintenance	19,014			—			12,533			6,481
Depreciation and amortization	94,512			—			66,975			27,537
Taxes other than income	15,682			45			9,743			5,894
Operating Income (Loss)	$	411,240		$	(649	)	$	346,225		$	65,664

Nine Months Ended
September 30, 2012
	NVE Consolidated			NVE Other			NPC Electric			SPPC Total			SPPC Electric			SPPC Gas
Operating Revenues	$	2,378,606		$	12		$	1,751,165		$	627,429		$	549,886		$	77,543
Energy Costs:
Fuel for power generation	400,936			—			285,799			115,137			115,137			—
Purchased power	486,894			—			388,494			98,400			98,400			—
Gas purchased for resale	46,491			—			—			46,491			—			46,491
Deferred Energy	(30,285		)	—			(15,461		)	(14,824		)	(13,854		)	(970		)
Energy efficiency program costs	76,609			—			65,466			11,143			11,143			—
Total Costs	$	980,645		$	—		$	724,298		$	256,347		$	210,826		$	45,521
Gross Margin	$	1,397,961		$	12		$	1,026,867		$	371,082		$	339,060		$	32,022
Other operating expenses	307,080			2,382			200,484			104,214
Maintenance	76,190			—			52,594			23,596
Depreciation and amortization	281,690			—			201,096			80,594
Taxes other than income	44,457			282			26,793			17,382
Operating Income (Loss)	$	688,544		$	(2,652	)	$	545,900		$	145,296

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 01, 2013
Entity Information [Line Items]
Entity Registrant Name	NV Energy, Inc.
Entity Central Index Key	0000741508
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		235,581,074
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013
Nevada Power Company
Entity Information [Line Items]
Entity Registrant Name	Nevada Power Company
Entity Central Index Key	0000071180
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013
Sierra Pacific Power Company
Entity Information [Line Items]
Entity Registrant Name	Sierra Pacific Power Company
Entity Central Index Key	0000090144
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013

XML

REGULATORY ACTIONS (Tables)

9 Months Ended

Sep. 30, 2013

REGULATORY ACTIONS [Abstract]

Summary of Deferred Energy Amounts

The following deferred energy amounts were included in the consolidated balance sheets as of September 30, 2013 (dollars in thousands):

	September 30, 2013
	NVE Total			NPC Electric			SPPC Electric			SPPC Gas
Deferred Energy
Cumulative Deferred Balance authorized in 2013 DEAA	$	(152,990	)	$	(102,227	)	$	(32,693	)	$	(18,070	)
2013 Amortization	111,977			69,288			23,695			18,994
2013 Deferred Energy Under Collections (1)	118,397			95,465			19,697			3,235
Deferred Energy Balance at September 30, 2013 - Subtotal	$	77,384		$	62,526		$	10,699		$	4,159
Reinstatement of deferred energy (effective 6/07, 10 years)	89,906			89,906			—			—
Total Deferred Energy	$	167,290		$	152,432		$	10,699		$	4,159
Current Assets
Deferred energy	$	82,235		$	68,391		$	10,322		$	3,522
Non-current Assets
Deferred energy	85,055			84,041			377			637
Total Net Deferred Energy	$	167,290		$	152,432		$	10,699		$	4,159

⁽¹⁾  These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting Policies, Deferred Energy Accounting, of the Notes to the Financial Statements in the 2012 Form 10-K.

Summary of Rate Filings

The September PUCN order includes the following changes in revenue requirement (dollars in millions):

	Effective Date	Authorized Revenue Requirement			Present Revenue Requirement		$ Change in Revenue Requirement
Revenue Requirement Subject To Change:
REPR (1)	Oct. 2013	$	42.3		$	44.4	$	(2.1	)
TRED (1)	Oct. 2013	7.4			6.3		1.1
EEPR Base (1)	Oct. 2013	6.0			5.6		0.4
EEPR Amortization (1)	Oct. 2013	(2.1		)	1.8		(3.9		)
EEIR Base (2)	Oct. 2013	5.5			4.7		0.8
EEIR Amortization (3)	Oct. 2013	(3.7		)	1.9		(5.6		)
Total Revenue Requirement		$	55.4		$	64.7	$	(9.3	)

⁽¹⁾ Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income.

⁽²⁾ The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if SPPC earns in excess of its authorized ROR. In future periods, SPPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

⁽³⁾ Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.

The September PUCN order includes the following changes in revenue requirement (dollars in millions):

	Effective Date	Authorized Revenue Requirement			Present Revenue Requirement		$ Change in Revenue Requirement
Revenue Requirement Subject To Change:
REPR (1)	Oct. 2013	$	28.4		$	38.7	$	(10.3	)
TRED (1)	Oct. 2013	15.7			15.9		(0.2		)
EEPR Base (1)	Oct. 2013	45.9			32.6		13.3
EEPR Amortization (1)	Oct. 2013	(29.9		)	9.0		(38.9		)
EEIR Base (2)	Oct. 2013	15.1			10.6		4.5
EEIR Amortization (3)	Oct. 2013	(17.2		)	10.7		(27.9		)
Total Revenue Requirement		$	58.0		$	117.5	$	(59.5	)

⁽¹⁾  Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income.

⁽²⁾  The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if NPC earns in excess of its authorized ROR. In future periods, NPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR.

⁽³⁾  Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013.