NEVADA POWER CO - FORM 10-Q - November 6, 2015

Attached files

file	filename
EX-15 - EXHIBIT 15 - NEVADA POWER CO	npc93015ex15.htm
EX-31.1 - EXHIBIT 31.1 - NEVADA POWER CO	npc93015ex311.htm
EX-32.1 - EXHIBIT 32.1 - NEVADA POWER CO	npc93015ex321.htm
EX-32.2 - EXHIBIT 32.2 - NEVADA POWER CO	npc93015ex322.htm
EX-31.2 - EXHIBIT 31.2 - NEVADA POWER CO	npc93015ex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2015

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _____ to _____



Commission File Number	Exact name of registrant as specified in its charter; State or other jurisdiction of incorporation or organization	IRS Employer Identification No.
000-52378	NEVADA POWER COMPANY	88-0420104
	(A Nevada Corporation)
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	702-402-5000

	Securities registered pursuant to Section 12(b) of the Act: None
	Securities registered pursuant to Section 12(g) of the Act:
	Common Stock, $1.00 stated value

Indicate by check mark whether the 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 T No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes T No o

Indicate by check mark whether the 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" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	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 T

All shares of outstanding common stock of Nevada Power Company are held by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of October 31, 2015, 1,000 shares of common stock, $1.00 stated value, were outstanding.

TABLE OF CONTENTS



PART I
Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24
Item 4.	Controls and Procedures	24

PART II

Item 1.	Legal Proceedings	25
Item 1A.	Risk Factors	25
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25
Item 3.	Defaults Upon Senior Securities	25
Item 4.	Mine Safety Disclosures	25
Item 5.	Other Information	25
Item 6.	Exhibits	25
Signatures		26
Exhibit Index		27

Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 2 through 4, and Part II - Items 1 through 6, the following terms have the definitions indicated.



Nevada Power Company and Related Entities

Company		Nevada Power Company and its subsidiaries
BHE		Berkshire Hathaway Energy Company
BHE Merger		On December 19, 2013, NV Energy, Inc. became an indirect wholly owned subsidiary of BHE
NV Energy		NV Energy, Inc.
Berkshire Hathaway		Berkshire Hathaway Inc.
Sierra Pacific		Sierra Pacific Power Company, an electric and natural gas utility wholly owned by NV Energy
Clark Generating Station		1,103-megawatt generating facility in Nevada
Goodsprings		5-megawatt waste heat recovery facility in Nevada
Harry Allen Generating Station		628-megawatt generating facility in Nevada
Higgins Generating Station		530-megawatt generating facility in Nevada
Lenzie Generating Station		1,102-megawatt generating facility in Nevada
Las Vegas Generating Station		272-megawatt generating facility in Nevada
Navajo Generating Station		2,250-megawatt generating facility in Arizona
Nellis Generating Station		15-megawatt generating facility under construction in Nevada
ON Line		500-kilovolt transmission line connecting the Company and Sierra Pacific
Reid Gardner Generating Station		257-megawatt generating facility in Nevada
Silverhawk Generating Station		520-megawatt generating facility in Nevada
Sun Peak Generating Station		210-megawatt generating facility in Nevada

Certain Industry Terms

AFUDC		Allowance for Funds Used During Construction
California ISO		California Independent System Operator Corporation
EEIR		Energy Efficiency Implementation Rate
EEPR		Energy Efficiency Program Rate
EIM		Energy Imbalance Market
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GHG		Greenhouse Gases
GWh		Gigawatt Hours
MW		Megawatts
MWh		Megawatt Hours
PUCN		Public Utilities Commission of Nevada

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the Company's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of the Company and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:


•	general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including reliability and safety standards, affecting the Company's operations or related industries;


•	changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;


•	the outcome of rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company's ability to recover costs in rates in a timely manner;


•	changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and distributed generation measures and programs, that could affect customer growth and usage, electricity supply or the Company's ability to obtain long-term contracts with customers and suppliers;


•	performance, availability and ongoing operation of the Company's generating facilities, including facilities not operated by the Company, due to the impacts of market conditions, outages and repairs, transmission constraints, weather and operating conditions;


•	a high degree of variance between actual and forecasted load or generation that could impact the Company's hedging strategy and the cost of balancing its generation resources with its retail load obligations;


•	changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;


•	the financial condition and creditworthiness of the Company's significant customers and suppliers;


•	changes in business strategy or development plans;


•	availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in the London Interbank Offered Rate, the base interest rate for the Company's credit facility;


•	changes in the Company's credit ratings;


•	the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;


•	the impact of inflation on costs and the Company's ability to recover such costs in rates;


•	increases in employee healthcare costs, including the implementation of the Affordable Care Act;


•	the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements related to the Company's participation in NV Energy's benefit plans;


•	unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generating facilities and infrastructure additions;

iii


•	the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company's consolidated financial results;


•	the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the Company's control or by a breakdown or failure of the Company's operating assets, including storms, floods, fires, earthquakes, explosions, landslides, litigation, wars, terrorism and embargoes; and


•	other business or investment considerations that may be disclosed from time to time in the Company's filings with the United States Securities and Exchange Commission or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Company are described in its filings with the United States Securities and Exchange Commission, including Part II, Item 1A and other discussions contained in this Form 10‑Q. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.

PART I

Item 1. Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Las Vegas, Nevada

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries (the "Company") as of September 30, 2015, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2015 and 2014, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 2015 and 2014. These interim financial statements are the responsibility of the Company's management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Nevada Power Company and subsidiaries as of December 31, 2014, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 27, 2015, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2014 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 6, 2015

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	September 30,			December 31,
	2015			2014
ASSETS

Current assets:
Cash and cash equivalents	$	374		$	220
Accounts receivable, net	430			243
Inventories	78			88
Regulatory assets	—			57
Deferred income taxes	56			145
Other current assets	46			32
Total current assets	984			785

Property, plant and equipment, net	6,943			7,003
Regulatory assets	1,054			1,069
Other assets	65			78

Total assets	$	9,046		$	8,935

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	252		$	212
Accrued interest	39			60
Accrued property, income and other taxes	42			30
Regulatory liabilities	136			40
Current portion of long-term debt and capital lease obligations	225			264
Customer deposits	59			55
Other current liabilities	49			36
Total current liabilities	802			697

Long-term debt and capital lease obligations	3,091			3,312
Regulatory liabilities	294			326
Deferred income taxes	1,440			1,414
Other long-term liabilities	274			298
Total liabilities	5,901			6,047

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—			—
Other paid-in capital	2,308			2,308
Retained earnings	840			583
Accumulated other comprehensive loss, net	(3		)	(3		)
Total shareholder's equity	3,145			2,888

Total liabilities and shareholder's equity	$	9,046		$	8,935

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

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2015			2014			2015			2014

Operating revenue	$	878		$	867		$	1,944		$	1,879

Operating costs and expenses:
Cost of fuel, energy and capacity	362			368			879			855
Operating and maintenance	101			113			273			282
Depreciation and amortization	74			69			222			204
Property and other taxes	12			10			31			31
Total operating costs and expenses	549			560			1,405			1,372

Operating income	329			307			539			507

Other income (expense):
Interest expense	(48		)	(51		)	(141		)	(154		)
Allowance for borrowed funds	1			—			2			—
Allowance for equity funds	1			—			3			—
Other, net	4			10			15			20
Total other income (expense)	(42		)	(41		)	(121		)	(134		)

Income before income tax expense	287			266			418			373
Income tax expense	100			98			147			137
Net income	$	187		$	168		$	271		$	236

The accompanying notes are an integral part of these consolidated financial statements.

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)



									Accumulated
				Other					Other			Total
	Common Stock			Paid-in		Retained			Comprehensive			Shareholder's
	Shares	Amount		Capital		Earnings			Loss, Net			Equity
Balance, December 31, 2013	1,000	$	—	$	2,308	$	586		$	(4	)	$	2,890
Net income	—	—		—		236			—			236
Other	—	—		—		—			1			1
Balance, September 30, 2014	1,000	$	—	$	2,308	$	822		$	(3	)	$	3,127

Balance, December 31, 2014	1,000	$	—	$	2,308	$	583		$	(3	)	$	2,888
Net income	—	—		—		271			—			271
Dividends declared	—	—		—		(13		)	—			(13		)
Other	—	—		—		(1		)	—			(1		)
Balance, September 30, 2015	1,000	$	—	$	2,308	$	840		$	(3	)	$	3,145

The accompanying notes are an integral part of these consolidated financial statements.

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2015			2014

Cash flows from operating activities:
Net income	$	271		$	236
Adjustments to reconcile net income to net cash flows from operating activities:
(Gain) loss on nonrecurring items	(3		)	15
Depreciation and amortization	222			204
Allowance for equity funds	(3		)	—
Deferred income taxes and amortization of investment tax credits	123			137
Amortization of deferred energy	40			64
Deferred energy	133			(44		)
Amortization of other regulatory assets and liabilities	16			36
Other, net	32			31
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(232		)	(249		)
Inventories	10			(1		)
Accounts payable and other liabilities	13			22
Net cash flows from operating activities	622			451

Cash flows from investing activities:
Capital expenditures	(214		)	(147		)
Proceeds from sale of assets	9			—
Other, net	10			—
Net cash flows from investing activities	(195		)	(147		)

Cash flows from financing activities:
Repayments of long-term debt and capital lease obligations	(260		)	(10		)
Dividends paid	(13		)	—
Net cash flows from financing activities	(273		)	(10		)

Net change in cash and cash equivalents	154			294
Cash and cash equivalents at beginning of period	220			126
Cash and cash equivalents at end of period	$	374		$	420

The accompanying notes are an integral part of these consolidated financial statements.

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Organization and Operations

Nevada Power Company, together with its subsidiaries (collectively, the "Company"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company ("Sierra Pacific") and certain other subsidiaries. The Company is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers, primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2015 and for the three- and nine-month periods ended September 30, 2015 and 2014. The results of operations for the three- and nine-month periods ended September 30, 2015 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2014 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2015.

(2) New Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2015-03, which amends FASB Accounting Standards Codification ("ASC") Subtopic 835-30, "Interest - Imputation of Interest." The amendments in this guidance require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability instead of as an asset. This guidance is effective for interim and annual reporting periods beginning after December 15, 2015, with early adoption permitted. This guidance must be adopted retrospectively, wherein the balance sheet of each period presented should be adjusted to reflect the new guidance. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):



		As of
	Depreciable Life	September 30,			December 31,
	Depreciable Life	2015			2014
Utility plant in-service:
Generation	25 - 80 years	$	4,158		$	4,034
Distribution	20 - 65 years	3,083			3,018
Transmission	45 - 65 years	1,781			1,757
General and intangible plant	5 - 65 years	690			669
Utility plant in-service		9,712			9,478
Accumulated depreciation and amortization		(2,937		)	(2,599		)
Utility plant in-service, net		6,775			6,879
Other non-regulated, net of accumulated depreciation and amortization	5 - 65 years	4			4
Plant in-service, net		6,779			6,883
Construction work-in-progress		164			120
Property, plant and equipment, net		$	6,943		$	7,003

(4) Regulatory Matters

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the Public Utilities Commission of Nevada ("PUCN").

Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

Energy Efficiency Implementation Rates and Energy Efficiency Program Rates

In July 2010, regulations were adopted by the PUCN that authorizes an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN through energy efficiency implementation rates ("EEIR"). As a result, the Company files annually to adjust energy efficiency program rates ("EEPR") and EEIR for over- or under-collected balances, which are effective in October of the same year.

The PUCN's final order approving the BHE Merger stipulated that the Company would not seek recovery of any lost revenue for calendar year 2014 in an amount that exceeded 50% of the lost revenue that the Company could otherwise request. In February 2014, the Company filed an application with the PUCN to reset the EEIR and EEPR. In June 2014, the PUCN accepted a stipulation to adjust the EEIR, as of July 1, 2014, to collect 50% of the estimated lost revenue that the Company would otherwise be allowed to recover for the 2014 calendar year. The EEIR was effective from July through December 2014, reset on January 1, 2015 and was in effect through September 2015. To the extent the Company's earned rate of return exceeds the rate of return used to set base general rates, the Company is required to refund to customers EEIR revenue collected.

In February 2015, the Company filed an application to reset the EEIR and EEPR. In August 2015, the PUCN accepted a stipulation for the Company to calculate the base EEIR using a revised methodology for calculating lost revenue and for the Company to make a $5 million reduction to the EEPR revenue requirement to more accurately reflect the actual level of spending and to minimize any over collection from its customers. The reset of the EEIR and EEPR was effective October 1, 2015 and remains in effect through September 30, 2016. The current EEIR liability is $11 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of September 30, 2015.

General Rate Case

In May 2014, the Company filed a general rate case with the PUCN. In July 2014, the Company made its certification filing, which requested incremental annual revenue relief in the amount of $38 million, or an average price increase of 2%. In October 2014, the Company reached a settlement agreement with certain parties agreeing to a zero increase in the revenue requirement. In October 2014, the PUCN issued an order in the general rate case filing that accepted the settlement. The order provides for increases in the fixed-monthly service charge for customers with a corresponding decrease in the base tariff general rate effective January 1, 2015. As a result of the order, the Company recorded $15 million in asset impairments related to property, plant and equipment and $5 million of regulatory asset impairments, which are included in operating and maintenance on the Consolidated Statements of Operations for the three- and nine-month periods ended September 30, 2014. Additionally, the Company recorded a $5 million gain in other, net on the Consolidated Statement of Operations for the three- and nine-month periods ended September 30, 2014 related to the disposition of property. In October 2014, a party filed a petition for reconsideration of the PUCN order. In November 2014, the PUCN granted the petition for reconsideration and reaffirmed the order issued in October 2014.

2013 Federal Energy Regulatory Commission ("FERC") Transmission Rate Case

In May 2013, the Company, along with Sierra Pacific, filed an application with the FERC to establish single system transmission and ancillary service rates. The combined filing requested incremental rate relief of $17 million annually to be effective January 1, 2014. In August 2013, the FERC granted the companies' request for a rate effective date of January 1, 2014 subject to refund, and set the case for hearing or settlement discussions. On January 1, 2014, the Company implemented the filed rates in this case subject to refund as set forth in the FERC's order.

In September 2014, the Company, along with Sierra Pacific, filed an unopposed settlement offer with the FERC on behalf of NV Energy and the intervening parties providing rate relief of $4 million. The settlement offer would resolve all outstanding issues related to this case. In addition, a preliminary order from the administrative law judge granting the motion for interim rate relief was issued, which authorizes the Company to institute the interim rates effective September 1, 2014, and begin billing transmission customers under the settlement rates for service provided on and after that date. In January 2015, the FERC approved the settlement and refunds were issued.

(5) Employee Benefit Plans

The Company is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of the Company. Amounts attributable to the Company were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):



	As of
	September 30,			December 31,
	2015			2014
Qualified Pension Plan -
Other long-term liabilities	$	(26	)	$	(23	)

Non-Qualified Pension Plans:
Other current liabilities	(1		)	(1		)
Other long-term liabilities	(9		)	(9		)

Other Postretirement Plans -
Other long-term liabilities	1			1

(6) Risk Management and Hedging Activities

The Company is exposed to the impact of market fluctuations in commodity prices and interest rates. The Company is principally exposed to electricity, natural gas and coal commodity price risk primarily through the Company's obligation to serve retail customer load in its regulated service territory. The Company's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. The Company does not engage in proprietary trading activities.

The Company has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed‑rate long-term debt and by monitoring market changes in interest rates. Additionally, the Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of the Company's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):



	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
As of September 30, 2015
Commodity liabilities⁽¹⁾	$	(9	)	$	(16	)	$	(25	)

As of December 31, 2014
Commodity liabilities⁽¹⁾	$	(9	)	$	(21	)	$	(30	)


(1)	The Company's commodity derivatives not designated as hedging contracts will be included in regulated rates when settled and as of September 30, 2015 and December 31, 2014, a regulatory asset of $25 million and $30 million, respectively, was recorded related to the derivative liability of $25 million and $30 million, respectively.

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contracts with indexed and fixed price terms that comprise the mark-to-market values as of (in millions):



	Unit of	September 30,		December 31,
	Measure	2015		2014
Electricity sales	Megawatt hours	(3	)	(3	)
Natural gas purchases	Decatherms	157		115

Credit Risk

The Company is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent the Company's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Company analyzes the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Company enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, the Company exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts may either specifically provide rights to demand cash or other security in the event of a credit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2015, credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features was $4 million as of September 30, 2015 and December 31, 2014, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.


(7)	Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:


•	Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

•

Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).


•	Level 3 - Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

The following table presents the Company's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):



	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3			Total
As of September 30, 2015
Assets - investment funds	$	9	$	—	$	—		$	9

Liabilities - commodity derivatives	$	—	$	—	$	(25	)	$	(25	)

As of December 31, 2014
Assets - investment funds	$	20	$	—	$	—		$	20

Liabilities - commodity derivatives	$	—	$	—	$	(30	)	$	(30	)

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, related volatility, counterparty creditworthiness and duration of the contracts. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of the Company's nonperformance risk on its liabilities, which as of September 30, 2015 and December 31, 2014, had an immaterial impact to the fair value of its derivative contracts. As such, the Company considers its derivative contracts to be valued using Level 3 inputs. Refer to Note 6 for further discussion regarding the Company's risk management and hedging activities.

The Company's investment funds are accounted for as trading securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

The following table reconciles the beginning and ending balances of the Company's commodity derivative liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2015			2014			2015			2014
Beginning balance	$	(33	)	$	(33	)	$	(30	)	$	(47	)
Changes in fair value recognized in regulatory assets	2			—			(3		)	12
Purchases	—			1			—			—
Settlements	6			3			8			6
Ending balance	$	(25	)	$	(29	)	$	(25	)	$	(29	)

The Company's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of the Company's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long‑term debt (in millions):



	As of September 30, 2015				As of December 31, 2014
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	2,818	$	3,314	$	3,066	$	3,712


(8)	Commitments and Contingencies

Environmental Laws and Regulations

In June 2013, the Nevada State Legislature passed Senate Bill No. 123 ("SB 123"), which included, in significant part:


•	Accelerating the plan to retire 800 megawatts ("MW") of coal plants, starting as soon as December 31, 2014;


•	Replacement of such coal plants by issuing requests for proposals for 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 additional electric generating capacity; and


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

In May 2014, the Company filed its Emissions Reduction Capacity Replacement Plan ("ERCR Plan") in compliance with SB 123 enacted by the 2013 Nevada Legislature. The filing proposed, among other items, the retirement of Reid Gardner Generating Station units 1, 2 and 3 in 2014 and unit 4 in 2017; the elimination of the Company's ownership interest in Navajo Generating Station in 2019; and a plan to replace the generating capacity being retired, as required by SB 123. The ERCR Plan includes the issuance of requests for proposals for 300-MW of renewable energy to be issued between 2014 and 2016; the acquisition of a 272‑MW natural gas co-generating facility in 2014; the acquisition of a 210-MW natural gas peaking facility in 2014; the construction of a 15-MW solar photovoltaic facility expected to be placed in-service in 2015; and the construction of a 200-MW solar photovoltaic facility expected to be placed in-service in 2016. In the second quarter of 2014, the Company executed various contractual agreements to fulfill the proposed ERCR Plan, which are subject to the PUCN approval. The PUCN issued an order dated October 28, 2014 removing the 200-MW solar photovoltaic facility proposed by the Company from the ERCR Plan but accepting the remaining requests. In November 2014, the Company filed a petition for reconsideration, but in December 2014, the PUCN upheld the original order from October 2014 with respect to material matters. In December 2014, the Company filed its acceptance of the modifications to the ERCR Plan.

In July 2015, the Company filed an amendment to its ERCR Plan with the PUCN. In September 2015, the PUCN approved the filed amendment requesting two renewable power purchase agreements with 100‑MW solar photovoltaic generating facilities related to the replacement of coal plants. Each of these agreements were entered into by issuing requests for proposals for the procurement of energy through the competitive solicitation process that was set forth in the Company's ERCR Plan in compliance with SB 123. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123. As a result, the Company will not proceed with issuance of a third 100-MW request for proposal for renewable energy until such time as the PUCN determines the Company has satisfactorily demonstrated a need for such electric generating capacity.

Reid Gardner Generation Station

In October 2011, the Company received a request for information from the Environmental Protection Agency Region 9 under Section 114 of the Clean Air Act requesting current and historical operations and capital project information for the Company's Reid Gardner Generating Station located near Moapa, Nevada. The Environmental Protection Agency'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 Environmental Protection Agency relating to the plant. The Company completed its responses to the Environmental Protection Agency during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, the Company cannot predict the impact, if any, associated with this information request.

Legal Matters

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.

November 2005 Land Investors

In 2006, November 2005 Land Investors, LLC ("NLI") purchased from the United States through the Bureau of Land Management 2,675 acres of land located in North Las Vegas, Nevada. A small portion of the land is traversed by a 500 kilovolt ("kV") transmission line owned by the Company and sited pursuant to a pre-existing right-of-way grant from the Bureau of Land Management. Subsequent to NLI's purchase, a dispute arose as to whether the Company owed rent and, if it did, the amount owed to NLI under the right-of-way grant. NLI eventually "terminated" the right-of-way grant and brought claims against the Company for breach of contract, inverse condemnation and trespass. The Company counterclaimed for express condemnation of a perpetual easement over the right-of-way corridor. The matter proceeded to trial in the Eighth District Court, Clark County, Nevada ("Eighth District Court"). In September 2013, the Eighth District Court awarded NLI $1 million for unpaid rent and $5 million for inverse condemnation, plus interest and attorneys' fees, bringing the total judgment to $12 million. The Eighth District Court also found the Company was entitled to judgment in its favor on its counterclaim for condemnation of the right-of-way corridor. The Company posted the required bond of $12 million and appealed to the Nevada Supreme Court. In June 2015, the parties finalized a settlement in this matter, separate from the court order above, and final documents dismissing the claims have been filed with the Eighth District Court. The settlement did not have a material impact to the Company's Consolidated Financial Statements.

Park Highlands

The Company has six other rights-of-way located on the same 2,675 acres of land located in North Las Vegas, Nevada, commonly referred to as the Park Highlands properties. NLI purportedly also terminated the other six rights‑of‑way. On January 2, 2015, KBS SOR Park Highlands, LLC ("KBS") filed a complaint in the Eighth District Court relating to one of the six rights‑of‑way, specifically the right-of-way that relates to a 230‑kV line that traverses the property. In the complaint, KBS raised the same claims previously raised by NLI in the litigation relating to the 500‑kV line. On January 9, 2015, the Company filed an action in the Eighth District Court relating to the six rights-of-way on the Park Highlands properties. This action sought a declaratory order quieting the Company's title to the rights-of-way or in the alternative condemning an easement interest in the property. In June 2015, the parties finalized a settlement in this matter and final documents dismissing the claims have been filed with the Eighth District Court. The settlement did not have a material impact to the Company's Consolidated Financial Statements.

Skye Canyon

In 2005, the Bureau of Land Management sold at auction a parcel of land commonly known as the Skye Canyon properties. The property was sold subject to preexisting rights-of-way held by the Company for the placement of electric transmission and distribution facilities. On January 9, 2015, the Company filed an action in the Eighth District Court relating to 14 rights‑of‑way located within the Skye Canyon properties. The action sought a declaratory order from the court that the rights-of-way held by the Company are still valid, establish the proper rent, if any, payable by the Company and to identify the proper party to whom rent is due. In June 2015, the parties finalized a settlement in this matter and final documents dismissing the claims have been filed with the Eighth District Court. The settlement did not have a material impact to the Company's Consolidated Financial Statements.

Sierra Club and Moapa Band of Paiute Indians

In August 2013, the Sierra Club and Moapa Band of Paiute Indians filed a complaint in federal district court in Nevada against the Company and the California Department of Water Resources, alleging that activities at the Reid Gardner Generating Station are causing imminent and substantial harm to the environment and that placement of coal combustion residuals at the on-site landfill constitute "open dumping" in violation of the Resource Conservation and Recovery Act. The complaint also alleges that the Reid Gardner Generating Station is engaged in the unlawful discharge of pollutants in violation of the Clean Water Act. The notice was issued pursuant to the citizen suit provisions of the Resource Conservation and Recovery Act and the Clean Water Act. The California Department of Water Resources was named as a co-defendant in the litigation due to its prior co-ownership in Reid Gardner Generating Station Unit 4. The complaint seeks various injunctive remedies, assessment of civil penalties, and reimbursement of plaintiffs' attorney and legal fees and costs. In August 2014, the federal district court dismissed without prejudice the plaintiff's amended complaint which sought civil penalties. In June 2015, the parties reached a settlement in principle in this matter. In October 2015, the settlement was accepted by the federal district court and did not have a material impact to the Company's Consolidated Financial Statements.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

General

The Company's 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. The Company is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. 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 Company. Additionally, the timely recovery of purchased power, 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 Company.

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with the Company's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2015 and 2014

Net income for the third quarter of 2015 was $187 million, an increase of $19 million, or 11%, compared to 2014 due to $20 million of lower impairment costs resulting from the settlement of the general rate case in 2014, lower compensation costs, increased customer usage primarily due to the impacts of weather, lower debt interest expense, increased customer growth and a decrease in operating expenses related to the retirement of Reid Gardner Generating Station Units 1-3, partially offset by ON Line lease expense, which was deferred in 2014 but expensed in 2015, a gain on sale of property in 2014 and lower retail rates as a result of a rate design change from the 2014 general rate case effective January 2015.

Net income for the first nine months of 2015 was $271 million, an increase of $35 million, or 15%, compared to 2014 due to $20 million of lower impairment costs resulting from the settlement of the general rate case in 2014, lower debt interest expense, changes in contingent liabilities, increased customer growth, lower compensation costs and a decrease in operating expenses related to the retirement of Reid Gardner Generating Station Units 1-3, partially offset by ON Line lease expense, which was deferred in 2014 but expensed in 2015, a gain on sale of property in 2014 and higher depreciation and amortization expense.

Operating revenue and cost of fuel, energy and capacity are key drivers of the Company's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. The Company believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity, is therefore meaningful. A comparison of the Company's key operating results is as follows:



	Third Quarter										First Nine Months
	2015		2014		Change						2015		2014		Change
Gross margin (in millions):
Operating revenue	$	878	$	867	$	11		1		%	$	1,944	$	1,879	$	65		3		%
Cost of fuel, energy and capacity	362		368		(6		)	(2	)		879		855		24			3
Gross margin	$	516	$	499	$	17		3			$	1,065	$	1,024	$	41		4

GWh sold:
Residential	3,772		3,675		97			3		%	7,586		7,436		150			2		%
Commercial	1,429		1,361		68			5			3,560		3,474		86			2
Industrial	2,153		2,101		52			2			5,790		5,743		47			1
Other	55		56		(1		)	(2	)		153		155		(2		)	(1	)
Total retail	7,409		7,193		216			3			17,089		16,808		281			2
Wholesale	104		4		100			*			292		10		282			*
Total GWh sold	7,513		7,197		316			4			17,381		16,818		563			3

Average number of retail customers (in thousands):
Residential	786		771		15			2		%	781		767		14			2		%
Commercial	104		104		—			—			104		104		—			—
Industrial	2		2		—			—			2		2		—			—
Total	892		877		15			2			887		873		14			2

Average retail revenue per MWh	$	116.78	$	119.63	$	(2.85	)	(2	)	%	$	111.46	$	110.34	$	1.12		1		%

Heating degree days	—		—		—			—		%	624		709		(85		)	(12	)	%
Cooling degree days	2,350		2,246		104			5		%	3,767		3,645		122			3		%

Sources of energy (GWh)⁽¹⁾:
Coal	623		1,171		(548		)	(47	)	%	1,229		3,748		(2,519		)	(67	)	%
Natural gas	5,198		4,268		930			22			11,304		9,549		1,755			18
Total energy generated	5,821		5,439		382			7			12,533		13,297		(764		)	(6	)
Energy purchased	2,428		2,270		158			7			5,203		4,623		580			13
Total	8,249		7,709		540			7			17,736		17,920		(184		)	(1	)

* Not meaningful


(1)	GWh amounts are net of energy used by the related generating facilities.

Gross margin increased $17 million, or 3%, for the third quarter of 2015 compared to 2014 due to:


•	$11 million in higher energy efficiency program rate revenue, which is offset in operating and maintenance expense;


•	$6 million due to higher customer growth in 2015;


•	$3 million in higher customer usage in 2015, primarily due to the impacts of weather; and


•	$3 million in transmission revenue primarily due to increased ON Line usage.

The increase in gross margin was partially offset by:


•	$6 million due to lower retail rates as a result of a rate design change from the 2014 general rate case effective January 2015.

Operating and maintenance decreased $12 million, or 11%, for the third quarter of 2015 compared to 2014 due to $20 million of lower impairment costs resulting from the settlement of the general rate case in 2014, decreased amortizations of demand side management program costs, lower compensation costs and a decrease related to the retirement of Reid Gardner Generating Station Units 1-3. The decrease was offset by $11 million in higher energy efficiency program costs, which are fully recovered in operating revenue, and $8 million in ON Line lease expense, which was deferred in 2014 but expensed in 2015.

Depreciation and amortization increased $5 million, or 7%, for the third quarter of 2015 compared to 2014 due to higher regulatory amortizations as a result of the 2014 general rate case effective January 2015 and the acquisition of Reid Gardner Generating Station Unit 4 in 2014.

Interest expense decreased $3 million, or 6%, for the third quarter of 2015 compared to 2014 primarily due to redemption of $250 million Series L, 5.875% General and Refunding Mortgage Notes in January 2015.

Other, net decreased $6 million, or 60%, for the third quarter of 2015 compared to 2014 due to a gain on sale of property in 2014 and higher interest on deferred charges in 2015.

Income tax expense increased $2 million, or 2%, for the third quarter of 2015 compared to 2014 and the effective tax rate was 35% for 2015 and 37% for 2014. The effective tax rate decreased due to federal tax benefits currently related to domestic production activities.

Gross margin increased $41 million, or 4%, for the first nine months of 2015 compared to 2014 due to:


•	$24 million in higher energy efficiency program rate revenue, which is offset in operating and maintenance expense;


•	$11 million due to higher customer growth in 2015;


•	$5 million in transmission revenue primarily due to increased ON Line usage; and


•	$3 million in higher customer usage in 2015, primarily due to the impacts of weather.

The increase in gross margin was partially offset by:


•	$2 million due to lower retail rates as a result of a rate design change from the 2014 general rate case effective January 2015.

Operating and maintenance decreased $9 million, or 3%, for the first nine months of 2015 compared to 2014 due to $20 million of lower impairment costs resulting from the settlement of the general rate case in 2014, $14 million in decreased amortizations of demand side management program costs, changes in contingent liabilities, lower compensation costs and a decrease related to the retirement of Reid Gardner Generating Station Units 1-3. The decrease was offset by $26 million in ON Line lease expense and $24 million in higher energy efficiency program costs, which are fully recovered in operating revenue.

Depreciation and amortization increased $18 million, or 9%, for the first nine months of 2015 compared to 2014 due to higher regulatory amortizations as a result of the 2014 general rate case effective January 2015 and the acquisition of Reid Gardner Generating Station Unit 4 in 2014.

Interest expense decreased $13 million, or 8%, for the first nine months of 2015 compared to 2014 primarily due to redemption of $250 million Series L, 5.875% General and Refunding Mortgage Notes in January 2015.

Other, net decreased $5 million, or 25%, for the first nine months of 2015 compared to 2014 due to a gain on sale of property in 2014 and higher interest on deferred charges in 2015, partially offset by a gain on the sale of an equity investment in March 2015.

Income tax expense increased $10 million, or 7%, for the first nine months of 2015 compared to 2014 and the effective tax rate was 35% for 2015 and 37% for 2014. The effective tax rate decreased due to federal tax benefits currently related to domestic production activities.

Liquidity and Capital Resources

As of September 30, 2015, the Company's total net liquidity was $774 million consisting of $374 million in cash and cash equivalents and $400 million of revolving credit facility availability.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2015 and 2014 were $622 million and $451 million, respectively. The change was due to an increase in collections for deferred energy costs, increased customer growth and a one-time bill credit of $15 million to retail customers refunded in 2014 in connection with the BHE Merger. The increase was offset by higher refunds to customers for conservation and renewable programs, settlement payments of contingent liabilities and lower collections of demand side management programs.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2015 and 2014 were $(195) million and $(147) million, respectively. The change was primarily due to an increase in capital expenditures related to construction of the Nellis Solar Array, partially offset by the proceeds received from the sale of assets and an equity investment.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2015 and 2014 were $(273) million and $(10) million, respectively. The change was due to repayments of long-term debt and capital lease obligations and dividends paid to NV Energy in 2015.

In January 2015, the Company repaid the aggregate principal amount outstanding of $250 million 5.875% Series L General and Refunding Mortgage Notes at 100% of the principal amount plus accrued interest with the use of cash on hand and short-term borrowings. The short-term borrowings were repaid in June 2015.

Ability to Issue Debt

The Company's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2015, the Company has financing authority from the PUCN consisting of the ability to: (1) issue additional long-term debt securities of up to $725 million; (2) refinance up to $553 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion. The Company's revolving credit facility contains a financial maintenance covenant which the Company was in compliance with as of September 30, 2015. In addition, certain financing agreements contain covenants which are currently suspended as the Company's senior secured debt is rated investment grade. However, if the Company's senior secured debt ratings fall below investment grade by either Moody's Investors Service or Standard & Poor's, the Company would be subject to limitations under these covenants.

Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which the Company has access to external financing depends on a variety of factors, including the Company's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.

The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):



	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2014		2015		2015

Generation development	$	16	$	38	$	45
Distribution	73		123		167
Transmission system investment	4		2		2
Other	54		51		103
Total	$	147	$	214	$	317

Contractual Obligations

As of September 30, 2015, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2014.

Regulatory Matters

The Company is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2014, and new regulatory matters occurring in 2015.

State Regulatory Matters

In November 2014, one retail electric customer filed an application with the PUCN to purchase energy from a provider of a new electric resource and become a distribution only service customer. The application was denied in June 2015 and the customer subsequently filed a petition for reconsideration. In July 2015, the PUCN approved a settlement agreement between the customer and the Company. In October 2015, the PUCN approved a separate green energy agreement between the Company and the customer and tariff changes embedded in the settlement agreement. However, the customer has not withdrawn its petition for reconsideration. In May 2015, three additional customers filed applications to purchase energy from a provider of a new electric resource and become a distribution only service customer. The applications are pending with the PUCN.

Emissions Reduction and Capacity Replacement Plan

In July 2015, the Company filed an amendment to its Emissions Reduction and Capacity Replacement Plan ("ERCR Plan") with the PUCN. In September 2015, the PUCN approved the filed amendment requesting two renewable power purchase agreements with 100‑MW solar photovoltaic generating facilities related to the replacement of coal plants. Each of these agreements were entered into by issuing requests for proposals for the procurement of energy through the competitive solicitation process that was set forth in the Company's ERCR Plan in compliance with Senate Bill No. 123 ("SB 123"). In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123. As a result, the Company will not proceed with issuance of a third 100-MW request for proposal for renewable energy until such time as the PUCN determines the Company has satisfactorily demonstrated a need for such electric generating capacity.

Joint Dispatch Agreement Application

The Company and Sierra Pacific are currently parties to an Interim Joint Dispatch Agreement ("Interim JDA") which outlines the joint dispatch of their combined power supply resources utilizing ON Line. In March 2015, the Company and Sierra Pacific filed an application with the PUCN seeking approval of an indefinite Joint Dispatch Agreement ("JDA"). The JDA is intended to replace the currently effective Interim JDA, which terminates on December 31, 2015. Joint dispatch transactions addressed by the proposed JDA include real-time, hourly and daily transactions. The JDA also explicitly governs joint dispatch transactions between the Company and Sierra Pacific and the California ISO utilizing the California ISO's EIM.

The primary differences between the Interim JDA and the JDA relate to EIM transactions with the California ISO. The JDA establishes the Company as the EIM scheduling coordinator for both the Company and Sierra Pacific and recognizes that the joint dispatch costs and benefits associated with EIM transactions will be governed by the accounting protocols and allocations set forth in the JDA, which are unchanged from those currently in effect under the Interim JDA. In July 2015, the PUCN approved the JDA with minor modifications, and established December 31, 2019 as the termination date for the agreement. In September 2015, the JDA was approved by the FERC.

Advanced Metering Infrastructure

In October 2014, the PUCN issued an order directing the Company to provide information relating to failures in certain remote disconnect/reconnect electric meters the Company has installed after media reports were published that electric meter failures may have resulted in fire events. The Company completed an internal review in response to this and other federal, state and local inquiries relating to these events. The information compiled and submitted indicates that no fire has resulted from the remote disconnect/reconnect electric meters. Additionally, in October 2014, the Nevada State Fire Marshal issued a report concluding that the incidents of electric arcing fires continue to decrease in Nevada and at this time there is no statewide fire problem related to the replacement of electric meters. In December 2014, the Company filed the requested information with the PUCN. In March 2015, the PUCN staff made additional requests and in May 2015, the Company provided the follow up items and has not received any additional requests pertaining to this item. In September 2015, the Company provided the PUCN electric meter testing results from a third party laboratory. All tests of the integrity and functionality of the meters subject to the distress testing passed. Analysis and internal investigation is continuing, but the Company does not believe this will have a material adverse impact on the Consolidated Financial Statements.

Energy Imbalance Market

The Company and Sierra Pacific had previously announced plans to join the EIM in October 2015. The EIM is expected to reduce costs to serve customers through more efficient dispatch of a larger and more diverse pool of generation resources, more effectively integrate renewables and enhance reliability through improved situational awareness and responsiveness. In July 2015, following the issuance of an order by the FERC and in conjunction with the California ISO's announcement of a supplemental stakeholder process, the California ISO and NV Energy announced a delay in the EIM entrance date. In October 2015, the California ISO and NV Energy filed its Readiness Certification with the FERC; however NV Energy is awaiting the FERC's approval before participating in the EIM.

Environmental Laws and Regulations

The Company is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state and local agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Refer to "Liquidity and Capital Resources" for discussion of the Company's forecast environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2014.

Senate Bill 123 Compliance

In June 2013, SB 123 was signed into law. Among other things, SB 123 and regulations thereunder require the Company to file with the PUCN an emission reduction and capacity replacement plan by May 1, 2014. The plan must provide for the retirement or elimination of 300 MW of coal generating capacity by December 31, 2014, another 250 MW of coal generating capacity by December 31, 2017, and another 250 MW of coal generating capacity by December 31, 2019, along with replacement of such capacity with a mixture of constructed, acquired or contracted renewable and non-technology specific generating units. The plan also must set forth the expected timeline and costs associated with decommissioning coal-fired generating units that will be retired or eliminated pursuant to the plan.

The PUCN has the authority to approve or modify the emission reduction and capacity replacement plan filed by the Company. Given the PUCN may recommend and/or approve variations to the Company's resource plans relative to requirements under SB 123, the specific impacts of SB 123 on the Company cannot be determined.

Clean Air Act Regulations

National Ambient Air Quality Standards

The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour sulfur dioxide standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2020 sulfur dioxide standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of sulfur dioxide in 2012 or emitted more than 2,600 tons of sulfur dioxide and had an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. The EPA intends to promulgate final sulfur dioxide area designations no later than July 2, 2016.

In October 2015, the EPA released revised ambient air quality standards for ground level ozone, lowering the standard from 75 parts per billion to 70 parts per billion. Under the Clean Air Act, the EPA is required to finalize a list of areas that are in "nonattainment" with the new standard by October 1, 2017. Given the level at which the standard was set in conjunction with retirements and the installation of controls, the new standard is not expected to have a significant impact on the Company.

Mercury and Air Toxics Standards

Numerous lawsuits have been filed in the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") challenging the Mercury and Air Toxics Standards ("MATS"). In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the United States Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. Oral argument in the case was held before the United States Supreme Court in March 2015, and a decision was issued by the United States Supreme Court in June 2015, which reversed and remanded the MATS rule to the D.C. Circuit for further action. The United States Supreme Court held that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. The United States Supreme Court's decision did not vacate or stay implementation of the MATS rule and until the D.C. Circuit takes further action, the Company continues to have a legal obligation under the MATS rule and its permits issued by the states in which it operates to comply with the MATS rule.

Climate Change

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. The EPA entered into a settlement agreement with a number of parties, including certain state governments and environmental groups, in December 2010 to promulgate emissions standards covering GHG. In April 2012, the EPA proposed new source performance standards for new fossil-fueled generating facilities that would limit emissions of carbon dioxide to 1,000 pounds per MWh. As part of his Climate Action Plan, President Obama announced a national climate change strategy and issued a presidential memorandum requiring the EPA to issue a re-proposed GHG new source performance standard for fossil-fueled generating facilities by September 2013. The September 2013 GHG new source performance standards released by the EPA set different standards for coal-fueled and natural gas-fueled generating facilities. The proposed standard for natural gas-fueled generating facilities considered the size of the unit and the electricity sent to the grid from the unit. The proposed standards were published in the Federal Register January 8, 2014, and the public comment period closed in May 2014. On August 3, 2015, the EPA issued the final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" for coal-fueled generating facilities reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. Any new fossil-fueled generating facilities constructed by the Company will be required to meet the GHG new source performance standards.

Clean Power Plan

In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on four building blocks that it determined were the "Best System of Emission Reduction." The four building blocks include: (a) a 6% heat rate improvement from coal-fueled generating facilities; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities to 70%; (c) increased deployment of renewable and non-carbon generating resources; and (d) increased energy efficiency. Under this proposal, states could have utilized any measure to achieve the specified emission reduction goals, with an initial implementation period of 2020-2029 and the final goal to be achieved by 2030. When fully implemented, the proposal was expected to reduce carbon dioxide emissions in the power sector to 30% below 2005 levels by 2030. The final Clean Power Plan was released August 3, 2015 and changed the methodology upon which the Best System of Emission Reduction is based to include: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The EPA also changed the compliance period to begin in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh and 1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. The EPA also released on August 3, 2015, a draft federal plan as an option or backstop for states to utilize in the event they do not submit approvable state plans. The draft federal plan is expected to be open for a 90-day public comment period after publication in the Federal Register. States are required to submit initial implementation plans by September 2016, and may request an extension to September 2018. The full impacts of the final rule or the federal plan on the Company cannot be determined until the state develops its implementation plan or the federal plan is finalized. The Company has historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

The GHG rules and the Company's compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.

Coal Combustion Byproduct Disposal

In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts, presenting two alternatives to regulation under the Resource Conservation and Recovery Act ("RCRA"). The public comment period closed in November 2010. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and was effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of coal combustion residuals. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements.

As defined by the final rule, the Company operates ten evaporative surface impoundments and one landfill that contains coal combustion byproducts. The Company has assessed the impacts on asset retirement obligations as a result of the final rule and does not believe it has a material impact to the Company.

Collateral and Contingent Features

Debt of the Company is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the Company's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

The Company has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2015, the applicable credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of September 30, 2015, the Company would have been required to post $73 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of the Company's collateral requirements specific to the Company's derivative contracts.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10‑K for the year ended December 31, 2014. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2014.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A of the Company's Annual Report on Form 10-K for the year ended December 31, 2014. The Company's exposure to market risk and its management of such risk has not changed materially since December 31, 2014. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 1 of this Form 10‑Q for disclosure of the Company's derivative positions as of September 30, 2015.

Item 4. Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon that evaluation, the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that the Company's disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to management, including the Company's President (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company's internal control over financial reporting during the quarter ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II


Item 1.	Legal Proceedings

None.


Item 1A.	Risk Factors

There has been no material change to the Company's risk factors from those disclosed in Item 1A of the Company's Annual Report on Form 10‑K for the year ended December 31, 2014.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.


Item 3.	Defaults Upon Senior Securities

Not applicable.


Item 4.	Mine Safety Disclosures

None.


Item 5.	Other Information

Not applicable.


Item 6.	Exhibits

The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		NEVADA POWER COMPANY
		(Registrant)



Date:	November 6, 2015	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Senior Vice President, Chief Financial Officer and Director
		(principal financial and accounting officer)

EXHIBIT INDEX


Exhibit No.	Description


15	Awareness Letter of Independent Registered Public Accounting Firm.


31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101

The following financial information from Nevada Power Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholder's Equity, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail.

Attached files

NEVADA POWER CO Reports

Also read