SIERRA PACIFIC POWER CO - FORM 10-Q

Attached files

file	filename
EX-15 - EXHIBIT 15 - SIERRA PACIFIC POWER CO	sppc63015ex15.htm
EX-32.1 - EXHIBIT 32.1 - SIERRA PACIFIC POWER CO	sppc63015ex321.htm
EX-31.1 - EXHIBIT 31.1 - SIERRA PACIFIC POWER CO	sppc63015ex311.htm
EX-32.2 - EXHIBIT 32.2 - SIERRA PACIFIC POWER CO	sppc63015ex322.htm
EX-31.2 - EXHIBIT 31.2 - SIERRA PACIFIC POWER CO	sppc63015ex312.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 June 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.
000-00508	SIERRA PACIFIC POWER COMPANY	88-0044418
	(A Nevada Corporation)
	6100 Neil Road
	Reno, Nevada 89511
	775-834-4011

	Securities registered pursuant to Section 12(b) of the Act: None
	Securities registered pursuant to Section 12(g) of the Act:
	Common Stock, $3.75 par 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 Sierra Pacific 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 July 31, 2015, 1,000 shares of common stock, $3.75 par 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	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 4.	Controls and Procedures	21

PART II

Item 1.	Legal Proceedings	22
Item 1A.	Risk Factors	22
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
Item 3.	Defaults Upon Senior Securities	22
Item 4.	Mine Safety Disclosures	22
Item 5.	Other Information	22
Item 6.	Exhibits	22
Signatures		23
Exhibit Index		24

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.



Sierra Pacific Power Company and Related Entities

Company		Sierra Pacific 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.
Clark Mountain Generating Station		132-megawatt generating facility in Nevada
Nevada Power		Nevada Power Company, an electric utility wholly owned by NV Energy
Ft. Churchill Generating Station		226-megawatt generating facility in Nevada
ON Line		500-kilovolt transmission line connecting the Company and Nevada Power
NV Energize		NV Energy project which includes advanced meter infrastructure, Smart Grid Technology and meter data management
Tracy Generating Station		753-megawatt generating facility in Nevada
Valmy Generating Station		522-megawatt generating facility in Nevada

Certain Industry Terms

AFUDC		Allowance for Funds Used During Construction
California ISO		California Independent System Operator Corporation
Dth		Decatherms
EEIR		Energy Efficiency Implementation 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 and natural gas supply or the Company's ability to obtain long-term contracts with customers and suppliers;


•	performance and availability of the Company's generating facilities, including the impacts of 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;


•	the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;

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

Sierra Pacific Power Company

Las Vegas, Nevada

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries (the "Company") as of June 30, 2015, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2015 and 2014, and of changes in shareholder's equity and cash flows for the six-month periods ended June 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 Sierra Pacific 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

August 7, 2015

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	June 30,			December 31,
	2015			2014
ASSETS

Current assets:
Cash and cash equivalents	$	115		$	22
Accounts receivable, net	119			127
Inventories	42			40
Regulatory assets	—			32
Deferred income taxes	34			42
Other current assets	23			20
Total current assets	333			283

Property, plant and equipment, net	2,662			2,640
Regulatory assets	431			444
Other assets	17			21

Total assets	$	3,443		$	3,388

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	135		$	127
Accrued interest	15			15
Accrued property and other taxes	11			12
Regulatory liabilities	58			39
Current portion of long-term debt	451			1
Customer deposits	18			16
Other current liabilities	21			14
Total current liabilities	709			224

Long-term debt	748			1,199
Regulatory liabilities	238			262
Deferred income taxes	577			566
Other long-term liabilities	145			139
Total liabilities	2,417			2,390

Commitments and contingencies (Note 7)

Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	—			—
Other paid-in capital	1,111			1,111
Accumulated deficit	(83		)	(111		)
Accumulated other comprehensive loss, net	(2		)	(2		)
Total shareholder's equity	1,026			998

Total liabilities and shareholder's equity	$	3,443		$	3,388

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2015			2014			2015			2014

Operating revenue:
Regulated electric	$	201		$	179		$	397		$	356
Regulated natural gas	26			21			76			65
Total operating revenue	227			200			473			421

Operating costs and expenses:
Cost of fuel, energy and capacity	101			86			198			166
Natural gas purchased for resale	15			12			50			41
Operating and maintenance	39			39			75			73
Depreciation and amortization	28			26			56			52
Property and other taxes	7			6			14			12
Total operating costs and expenses	190			169			393			344

Operating income	37			31			80			77

Other income (expense):
Interest expense	(15		)	(15		)	(30		)	(30		)
Allowance for borrowed funds	1			1			1			1
Allowance for equity funds	—			1			1			2
Other, net	1			3			2			5
Total other income (expense)	(13		)	(10		)	(26		)	(22		)

Income before income tax expense	24			21			54			55
Income tax expense	8			7			19			19
Net income	$	16		$	14		$	35		$	36

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

SIERRA PACIFIC 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		Accumulated			Comprehensive			Shareholder's
	Shares	Amount		Capital		Deficit			Loss, Net			Equity

Balance, December 31, 2013	1,000	$	—	$	1,111	$	(93	)	$	(2	)	$	1,016
Net income	—	—		—		36			—			36
Balance, June 30, 2014	1,000	$	—	$	1,111	$	(57	)	$	(2	)	$	1,052

Balance, December 31, 2014	1,000	$	—	$	1,111	$	(111	)	$	(2	)	$	998
Net income	—	—		—		35			—			35
Dividends declared	—	—		—		(7		)	—			(7		)
Balance, June 30, 2015	1,000	$	—	$	1,111	$	(83	)	$	(2	)	$	1,026

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Six-Month Periods
	Ended June 30,
	2015			2014

Cash flows from operating activities:
Net income	$	35		$	36
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	56			52
Allowance for equity funds	(1		)	(2		)
Deferred income taxes and amortization of investment tax credits	19			19
Amortization of deferred energy	19			2
Deferred energy	47			(31		)
Amortization of other regulatory assets	(6		)	28
Other, net	(3		)	(9		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	7			22
Inventories	(2		)	(4		)
Accounts payable and other liabilities	25			(9		)
Net cash flows from operating activities	196			104

Cash flows from investing activities:
Capital expenditures	(98		)	(88		)
Other, net	2			—
Net cash flows from investing activities	(96		)	(88		)

Cash flows from financing activities:
Dividends paid	(7		)	—
Net cash flows from financing activities	(7		)	—

Net change in cash and cash equivalents	93			16
Cash and cash equivalents at beginning of period	22			67
Cash and cash equivalents at end of period	$	115		$	83

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Organization and Operations

Sierra Pacific 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 Nevada Power Company ("Nevada Power") and certain other subsidiaries. The Company is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. 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 June 30, 2015 and for the three- and six-month periods ended June 30, 2015 and 2014. The results of operations for the three- and six-month periods ended June 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 six-month period ended June 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 July 2015, the FASB decided to defer the effective date 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	June 30,			December 31,
	Depreciable Life	2015			2014
Utility plant in-service:
Electric generation	40-125 years	$	1,111		$	1,036
Electric distribution	20-70 years	1,351			1,321
Electric transmission	50-70 years	725			719
Electric general and intangible plant	5-65 years	131			123
Natural gas distribution	40-70 years	368			366
Natural gas general and intangible plant	8-10 years	13			13
Common general	5-65 years	245			234
Utility plant in-service		3,944			3,812
Accumulated depreciation and amortization		(1,356		)	(1,300		)
Utility plant in-service, net		2,588			2,512
Construction work-in-progress		74			128
Property, plant and equipment, net		$	2,662		$	2,640

(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 in March to adjust energy efficiency program rates 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 energy efficiency program rates. 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 remains 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. As a result, the Company has deferred recognition of EEIR revenue collected and has recorded a liability of $4 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of June 30, 2015.

General Rate Case

In connection with Nevada Power's general rate case filing in May 2014, as required by the PUCN, the Company made a "companion filing" for the purpose of documenting the costs and benefits of the Company's investment in the advanced service delivery program. In October 2014, the PUCN issued an order in the companion filing issued with the general rate case order that, among other things, provided for the implementation of new rates effective January 1, 2015 to begin recovery of costs associated with advance service delivery. The recovery of advanced service delivery costs will increase annual revenue approximately $10 million. As a result of the PUCN order in the companion filing issued with the Nevada Power general rate case order, the Company recorded $7 million in asset impairments related to property, plant and equipment and $1 million of regulatory asset impairments, which are included in operating and maintenance on the Consolidated Statements of Operations for the year ended December 31, 2014.

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

In May 2013, the Company, along with Nevada Power, 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 Nevada Power, 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 payable to NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):



	As of
	June 30,			December 31,
	2015			2014
Qualified Pension Plan -
Other long-term liabilities	$	(13	)	$	(13	)

Non-Qualified Pension Plans:
Other current liabilities	(1		)	(1		)
Other long-term liabilities	(10		)	(10		)

Other Postretirement Plans -
Other long-term liabilities	(34		)	(33		)


(6)	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 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 June 30, 2015				As of December 31, 2014
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,173	$	1,269	$	1,174	$	1,301


(7)	Commitments and Contingencies

Environmental Laws and Regulations

Valmy Generation Station

In June 2009, 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 Valmy Generating Station located in Valmy, Nevada. The Company co-owns and operates this coal-fueled generating facility. Idaho Power Company owns the remaining 50%. 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 in December 2009 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.

Caughlin Fire

On November 18, 2011, a fire was reported in the hills near Reno, Nevada (the "Caughlin Fire"). In January 2012, the Reno Fire Department issued a report in which they opined that "this fire was most likely the result of an electrical event in the area," and that "something such as a tree branch hitting the power-line" was a likely cause of the fire. The Company is continuing its investigation in the matter.

Subrogation lawsuits and individual claimant lawsuits have been filed against the Company in relation to the Caughlin Fire. The subrogation lawsuits have been brought by various insurance companies, and involve similar causes of action (negligence, inverse condemnation, trespass, nuisance, subrogation and strict liability). The individual lawsuits mostly alleged similar causes of action as outlined in the subrogation claims. The Company reached settlement of all the subrogation lawsuits in July 2014, which did not have a material impact to the Company.

In February 2015, all but one of the remaining individual plaintiffs entered into a settlement agreement. This settlement agreement did not have a material impact on the Company. The Company plans to vigorously defend the remaining lawsuit. The Company cannot assess or predict the outcome of the remaining lawsuit or if any other litigation may be brought on this matter.

Touch America Holdings

In January 2015, Brent Williams as Trustee of Touch America Holdings ("Touch America") filed a complaint in the United States Bankruptcy Court for the District of Delaware against the Company alleging Touch America owns certain underground communications conduit located at various places in the western United States that the Company also claims to own. The conduit at issue is believed to be located between Reno, Nevada and Spanish Fork, Utah as part of a larger duct bank system. In March 2015, the Company filed a response to the complaint and asserted a counterclaim to the conduit. In June 2015, the Company finalized terms and conditions with a third party quitclaiming its interest in the assets at issue in this case. The Company is seeking a dismissal by Touch America. The Company cannot assess or predict the outcome of the case at this time.

(8) Segment Information

The Company has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

The Company believes presenting gross margin allows the reader to assess the impact of the Company's regulatory treatment and its overall regulatory environment on a consistent basis and is meaningful. Gross margin is calculated as operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale ("Cost of sales"). The following tables provide information on a reportable segment basis (in millions):



	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2015		2014		2015		2014
Operating revenue:
Regulated electric	$	201	$	179	$	397	$	356
Regulated gas	26		21		76		65
Total operating revenue	$	227	$	200	$	473	$	421

Cost of sales:
Regulated electric	$	101	$	86	$	198	$	166
Regulated gas	15		12		50		41
Total cost of sales	$	116	$	98	$	248	$	207

Gross margin:
Regulated electric	$	100	$	93	$	199	$	190
Regulated gas	11		9		26		24
Total gross margin	$	111	$	102	$	225	$	214

Operating and maintenance:
Regulated electric	$	35	$	35	$	67	$	64
Regulated gas	4		4		8		9
Total operating and maintenance	$	39	$	39	$	75	$	73

Depreciation and amortization:
Regulated electric	$	24	$	23	$	48	$	45
Regulated gas	4		3		8		7
Total depreciation and amortization	$	28	$	26	$	56	$	52

Operating income:
Regulated electric	$	34	$	29	$	71	$	70
Regulated gas	3		2		9		7
Total operating income	$	37	$	31	$	80	$	77

Interest expense:
Regulated electric	$	14	$	14	$	28	$	28
Regulated gas	1		1		2		2
Total interest expense	$	15	$	15	$	30	$	30



	As of
	June 30,		December 31,
	2015		2014
Total assets:
Regulated electric	$	3,000	$	3,031
Regulated gas	322		327
Regulated common assets⁽¹⁾	121		30
Total assets	$	3,443	$	3,388


(1)	Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.

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 Second Quarter and First Six Months of 2015 and 2014

Overview

Net income for the second quarter of 2015 was $16 million, an increase of $2 million, or 14%, compared to 2014 due to a settlement payment associated with terminated transmission service, lower costs related to relinquishing an insurance claim in 2014 for a previously sold asset and increased revenues for the recovery of costs associated with advanced service delivery, partially offset by higher maintenance costs and regulatory amortizations.

Net income for the first six months of 2015 was $35 million, a decrease of $1 million, or 3%, compared to 2014 due to higher planned maintenance costs, increased regulatory amortizations and lower revenue due to a FERC rate change effective September 1, 2014, partially offset by a settlement payment associated with terminated transmission service, increased revenues for the recovery of costs associated with advanced service delivery and lower costs related to relinquishing an insurance claim in 2014 for a previously sold asset.

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

Electric Gross Margin



	Second Quarter										First Six Months
	2015		2014		Change						2015		2014		Change
Gross margin (in millions):
Operating electric revenue	$	201	$	179	$	22		12		%	$	397	$	356	$	41		12		%
Cost of fuel, energy and capacity	101		86		15			17			198		166		32			19
Gross margin	$	100	$	93	$	7		8			$	199	$	190	$	9		5

GWh sold:
Residential	489		484		5			1		%	1,080		1,078		2			—		%
Commercial	749		761		(12		)	(2	)		1,415		1,413		2			—
Industrial	774		730		44			6			1,491		1,417		74			5
Other	4		4		—			—			8		8		—			—
Total retail	2,016		1,979		37			2			3,994		3,916		78			2
Wholesale	163		134		29			22			345		344		1			—
Total GWh sold	2,179		2,113		66			3			4,339		4,260		79			2

Average number of retail customers (in thousands):
Residential	288		284		4			1		%	288		284		4			1		%
Commercial	46		46		—			—			46		46		—			—
Total	334		330		4			1			334		330		4			1

Average retail revenue per MWh	$	90.85	$	82.85	$	8.00		10		%	$	91.35	$	82.74	$	8.61		10		%

Heating degree days	566		459		107			23		%	2,234		2,319		(85		)	(4	)	%
Cooling degree days	319		259		60			23		%	319		259		60			23		%

Sources of energy (GWh)⁽¹⁾:
Coal	154		492		(338		)	(69	)	%	494		947		(453		)	(48	)	%
Natural gas	1,116		985		131			13			2,094		1,894		200			11
Total energy generated	1,270		1,477		(207		)	(14	)		2,588		2,841		(253		)	(9	)
Energy purchased	1,113		671		442			66			2,040		1,481		559			38
Total	2,383		2,148		235			11			4,628		4,322		306			7

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

Natural Gas Gross Margin



	Second Quarter								First Six Months
	2015		2014		Change				2015		2014		Change
Gross margin (in millions):
Operating natural gas revenue	$	26	$	21	$	5	24	%	$	76	$	65	$	11		17		%
Natural gas purchased for resale	15		12		3		25		50		41		9			22
Gross margin	$	11	$	9	$	2	22		$	26	$	24	$	2		8

Dth sold:
Residential	1,309		1,234		75		6	%	4,524		4,533		(9		)	—		%
Commercial	650		622		28		5		2,265		2,381		(116		)	(5	)
Industrial	315		281		34		12		840		788		52			7
Total retail	2,274		2,137		137		6		7,629		7,702		(73		)	(1	)

Average number of retail customers (in thousands)	158		156		2		1	%	158		156		2			1		%
Average revenue per retail Dth sold	$	11.16	$	9.72	$	1.44	15	%	$	9.75	$	8.30	$	1.45		17		%
Average cost of natural gas per retail Dth sold	$	6.69	$	5.62	$	1.07	19	%	$	6.54	$	5.32	$	1.22		23		%
Heating degree days	566		459		107		23	%	2,234		2,319		(85		)	(4	)	%

Electric gross margin increased $7 million, or 8%, for the second quarter of 2015 compared to 2014 due to:


•	$4 million related to a settlement payment associated with terminated transmission service,


•	$3 million from recovery of costs associated with advanced service delivery and


•	$1 million in higher energy efficiency program rate revenue, which is offset in operating and maintenance expense.

Natural gas gross margin increased $2 million, or 22%, for the second quarter of 2015 compared to 2014 primarily due to recovery of costs associated with advanced service delivery.

Operating and maintenance was flat for the second quarter of 2015 compared to 2014 due to increased planned maintenance costs primarily at the Valmy Generation Station and higher energy efficiency program costs, which are fully recovered in operating revenue, offset by relinquishing an insurance claim in 2014 for a previously sold asset.

Depreciation and amortization increased $2 million, or 8%, for the second quarter of 2015 compared to 2014 primarily due to regulatory amortizations.

Other, net decreased $2 million, or 67%, for the second quarter of 2015 compared to 2014 primarily due to lower carrying charges related to the recovery of costs associated with advanced service delivery approved in the companion filing of the 2014 Nevada Power general rate case effective January 1, 2015.

Income tax expense increased $1 million, or 14%, for the second quarter of 2015 compared to 2014 and the effective tax rate was 33% for 2015 and 2014. The increase in income tax expense is primarily due to higher pre-tax earnings.

Electric gross margin increased $9 million, or 5%, for the first six months of 2015 compared to 2014 due to:


•	$6 million from recovery of costs associated with advanced service delivery;


•	$4 million related to a settlement payment associated with terminated transmission service and


•	$2 million in higher energy efficiency program rate revenue, which is offset in operating and maintenance expense.

The increase in gross margin was partially offset by:


•	$2 million in lower revenue due to a FERC rate change effective September 1, 2014 and improved energy efficiency measures.

Natural gas gross margin increased $2 million, or 8%, for the first six months of 2015 compared to 2014 primarily due to recovery of costs associated with advanced service delivery.

Operating and maintenance increased $2 million, or 3%, for the first six months of 2015 compared to 2014 due to planned maintenance costs and higher energy efficiency program costs, which are fully recovered in operating revenue. This increase was partially offset by relinquishing an insurance claim in 2014 for a previously sold asset and lower compensation costs.

Depreciation and amortization increased $4 million, or 8%, for the first six months of 2015 compared to 2014 primarily due to regulatory amortizations.

Property and other taxes increased $2 million, or 17%, for the first six months of 2015 compared to 2014 primarily due to an increase in assessed property values.

Other, net decreased $3 million, or 60%, for the first six months of 2015 compared to 2014 primarily due to lower carrying charges related to the recovery of costs associated with advanced service delivery approved in the companion filing of the 2014 Nevada Power general rate case effective January 1, 2015.

Income tax expense was flat for the first six months of 2015 compared to 2014 and the effective tax rate was 35% for 2015 and 2014.

Liquidity and Capital Resources

As of June 30, 2015, the Company's total net liquidity was $365 million consisting of $115 million in cash and cash equivalents and $250 million of revolving credit facility availability.

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2015 and 2014 were $196 million and $104 million, respectively. The change was primarily due to an increase in collections for deferred energy costs, timing of payments related to purchased power in 2015, a one-time bill credit of $5 million to retail customers refunded in 2014 in connection with the BHE Merger, and higher collections from customers for the recovery of advanced service delivery costs. The increase is partially offset by higher refunds to customers for conservation and renewable programs.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2015 and 2014 were $(96) million and $(88) million, respectively. The change was primarily due to increased capital expenditures.

Financing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2015 and 2014 were $(7) million and $- million, respectively. The change was due to dividends paid to NV Energy.

Ability to Issue Debt

The Company's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of June 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 $350 million; (2) refinance up to $348 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $600 million. The Company's revolving credit facility contains a financial maintenance covenant which the Company was in compliance with as of June 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. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into the Company's regulated retail rates. 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):



	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2014		2015		2015

Distribution	$	45	$	56	$	89
Transmission system investment	5		1		3
Other	38		41		88
Total	$	88	$	98	$	180

Contractual Obligations

As of June 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

Joint Dispatch Agreement Application

The Company and Nevada Power 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 Nevada Power 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 Nevada Power 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 Nevada Power as the EIM scheduling coordinator for both the Company and Nevada Power 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 July 2015, the JDA was filed with the FERC for approval.

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. 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 Nevada Power have 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 change in the EIM entrance date to November 2015.

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.

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. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations and supporting information by the specified deadline of September 18, 2015. The EPA intends to promulgate final sulfur dioxide area designations no later than July 2, 2016.

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.

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.

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 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 will be 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 does not operate evaporative surface impoundments and operates 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 June 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 June 30, 2015, the Company would have been required to post $13 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.

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.

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 June 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.



		SIERRA PACIFIC POWER COMPANY
		(Registrant)



Date:	August 7, 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 Sierra Pacific Power Company's Quarterly Report on Form 10-Q for the quarter ended June 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.

SIERRA PACIFIC POWER CO - FORM 10-Q - August 7, 2015

Attached files

SIERRA PACIFIC POWER CO Reports