SIERRA PACIFIC POWER CO - FORM 10-Q

Attached files

file	filename
EXCEL - IDEA: XBRL DOCUMENT - SIERRA PACIFIC POWER CO	Financial_Report.xls
EX-15.EX-15 - AWARENESS LETTER OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - SIERRA PACIFIC POWER CO	sppc63014ex15.htm
EX-31.EX-31.1 - SECTION 302 CEO CERTIFICATION - SIERRA PACIFIC POWER CO	sppc63014ex311.htm
EX-32.EX-32.2 - SECTION 906 CFO CERTIFICATION - SIERRA PACIFIC POWER CO	sppc63014ex322.htm
EX-32.EX-32.1 - SECTION 906 CEO CERTIFICATION - SIERRA PACIFIC POWER CO	sppc63014ex321.htm
EX-31.EX-31.2 - SECTION 302 CFO CERTIFICATION - SIERRA PACIFIC POWER CO	sppc63014ex312.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, 2014

[ ] 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, 2014, 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	12
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	20
Item 4.	Controls and Procedures	20

PART II

Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	21
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	21
Item 3.	Defaults Upon Senior Securities	21
Item 4.	Mine Safety Disclosures	21
Item 5.	Other Information	21
Item 6.	Exhibits	21
Signatures		22
Exhibit Index		23

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
NV Energy		NV Energy, Inc.
Nevada Power		Nevada Power Company, an electric utility wholly owned by NV Energy
Ft. Churchill Generating Station		226-megawatt generating facility in Nevada

Certain Industry Terms

AFUDC		Allowance for Funds Used During Construction
Dth		Decatherms
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GWh		Gigawatt Hours
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 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;


•	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;


•	performance and availability of the Company's generating facilities, including the impacts of outages and repairs, transmission constraints, weather and operating conditions;


•	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 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;


•	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; 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 the Company's 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, 2014, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2014 and 2013, and of changes in shareholder's equity and cash flows for the six-month periods ended June 30, 2014 and 2013. 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, 2013, 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 March 31, 2014, 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, 2013 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 1, 2014

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	June 30,			December 31,
	2014			2013
ASSETS

Current assets:
Cash and cash equivalents	$	83		$	67
Accounts receivable, net	136			156
Inventories	47			43
Regulatory assets	46			15
Deferred income taxes	33			48
Other current assets	19			23
Total current assets	364			352

Property, plant and equipment, net	2,582			2,552
Regulatory assets	414			427
Other assets	49			38

Total assets	$	3,409		$	3,369

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	118		$	151
Accrued interest	15			15
Accrued property, income and other taxes	12			12
Accrued employee expenses	11			7
Regulatory liabilities	56			37
Current portion of long-term debt	1			1
Customer deposits and other	17			16
Total current liabilities	230			239

Long-term debt	1,200			1,199
Regulatory liabilities	249			243
Deferred income taxes	530			525
Other long-term liabilities	148			147
Total liabilities	2,357			2,353

Commitments and contingencies (Note 8)

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	(57		)	(93		)
Accumulated other comprehensive loss, net	(2		)	(2		)
Total shareholder's equity	1,052			1,016

Total liabilities and shareholder's equity	$	3,409		$	3,369

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,
	2014			2013			2014			2013

Operating revenue:
Electric	$	179		$	174		$	356		$	346
Natural gas	21			15			65			49
Total operating revenue	200			189			421			395

Operating costs and expenses:
Cost of fuel, energy and capacity	86			70			166			132
Natural gas purchased for resale	12			6			41			24
Operating and maintenance expense	39			48			73			96
Depreciation and amortization	26			27			52			52
Property and other taxes	6			7			12			13
Merger-related expenses	—			4			—			4
Total operating costs and expenses	169			162			344			321

Operating income	31			27			77			74

Other income (expense):
Interest expense, net of allowance for debt funds	(14		)	(16		)	(29		)	(32		)
Allowance for equity funds	1			—			2			1
Other, net	3			5			5			7
Total other income (expense)	(10		)	(11		)	(22		)	(24		)

Income before income tax expense	21			16			55			50
Income tax expense	7			5			19			17
Net income	$	14		$	11		$	36		$	33

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 at December 31, 2012	1,000	$	—	$	1,111	$	(71	)	$	(1	)	$	1,039
Net income	—	—		—		33			—			33
Dividends declared	—	—		—		(20		)	—			(20		)
Balance at June 30, 2013	1,000	$	—	$	1,111	$	(58	)	$	(1	)	$	1,052

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

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,
	2014			2013

Cash flows from operating activities:
Net income	$	36		$	33
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	52			52
Allowance for equity funds	(2		)	(1		)
Deferred income taxes and amortization of investment tax credits	19			17
Amortization of other regulatory assets	30			2
Other, net	(9		)	7
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(9		)	—
Inventories	(4		)	7
Accounts payable and other liabilities	(9		)	(9		)
Net cash flows from operating activities	104			108

Cash flows from investing activities:
Capital expenditures	(88		)	(57		)
Net cash flows from investing activities	(88		)	(57		)

Cash flows from financing activities:
Dividends paid	—			(20		)
Net cash flows from financing activities	—			(20		)

Net change in cash and cash equivalents	16			31
Cash and cash equivalents at beginning of period	67			61
Cash and cash equivalents at end of period	$	83		$	92

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 utility company serving electric retail customers, including residential, commercial and industrial customers, primarily in northern Nevada and retail natural gas customers in 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.

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, 2014 and for the three- and six-month periods ended June 30, 2014 and 2013. Certain amounts in the prior periods Consolidated Statement of Operations have been reclassified to conform to the current period's presentation. Such reclassifications did not impact previously reported net income. The results of operations for the three- and six-month periods ended June 30, 2014 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, 2013 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, 2014.

(2) New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, which creates FASB Accounting Standards Codification ("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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2016. Early application is not permitted. 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.

In February 2013, the FASB issued ASU No. 2013-04, which amends FASB ASC Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as well as other information about those obligations. This guidance is effective for interim and annual reporting periods beginning after December 15, 2013. The Company adopted this guidance on January 1, 2014. The adoption of this guidance did not have a material impact on the Company's 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
	June 30,			December 31,
	2014			2013
Utility plant in-service:
Electric generation	$	1,067		$	1,070
Electric distribution	1,308			1,289
Electric transmission	714			685
Electric intangible plant	124			138
Natural gas distribution	360			357
Natural gas intangible plant	13			13
Common general	233			212
Utility plant in-service	3,819			3,764
Accumulated depreciation and amortization	(1,324		)	(1,301		)
Utility plant in-service, net	2,495			2,463
Construction work-in-progress	87			89
Property, plant and equipment, net	$	2,582		$	2,552

(4) Regulatory Matters

Energy Efficiency Implementation Rates

The PUCN's final order approving the merger between BHE and NV Energy stipulated that the Company will not seek recovery of any lost revenue for calendar year 2014 in an amount that exceeds 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 energy efficiency implementation rate. In June 2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate, 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 energy efficiency implementation rate will be effective from July through December 2014 and will reset on January 1, 2015 and remain 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 energy efficiency implementation rate revenue collected. As a result, the Company has deferred recognition of energy efficiency implementation rate revenue collected and has recorded a liability of $3 million on the Consolidated Balance Sheets as of June 30, 2014.

2013 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. On August 5, 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 FERC's order. As of June 30, 2014 the Company accrued $1 million for amounts subject to rate refund, which is included in customer deposits and other on the Consolidated Balance Sheets. At this time management is unable to determine the final revenue impact of the case.

(5) Recent Financing Transactions

Credit Facility

In June 2014, the Company amended its $250 million secured credit facility expiring in March 2017, extending the maturity date to March 2018. The amended facility has a variable interest rate based on the London Interbank Offered Rate or a base rate, at the Company's option, plus a spread that varies based upon the Company's secured debt credit rating. The amended facility requires that the Company's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.68 to 1.0 as of the last day of each quarter.

(6) 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 income.

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



	As of
	June 30,			December 31,
	2014			2013
Qualified Pension Plan:
Other assets	$	16		$	18

Non-Qualified Pension Plans:
Customer deposits and other	(1		)	(1		)
Other long-term liabilities	(10		)	(11		)

Other Postretirement Plans:
Other long-term liabilities	(39		)	(38		)


(7)	Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, investments held in Rabbi trusts, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. 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 Financial Statements. 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, 2014				As of December 31, 2013
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,176	$	1,291	$	1,176	$	1,270


(8)	Commitments and Contingencies

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. The Company believes it is in material compliance with all applicable laws and regulations.

Valmy Generating 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, a 522-megawatt generating facility located in Valmy, Nevada. The Company owns 50% and operates this coal-fueled generating facility while Idaho Power Company owns the other 50% interest. 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 response 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.

Newmont Nevada Energy Investment - TS Power Plant

Newmont Nevada Energy Investment, LLC ("Newmont") owns a 203 megawatt coal-fueled power plant facility located in Eureka County, Nevada (the "TS Power Plant") that is interconnected to the Company's transmission system. As a result of system modifications required for a 500-kilovolt transmission line connecting the Company and Nevada Power ("ON Line"), Newmont will need to install certain protection equipment at its TS Power Plant. Newmont brought suit against the Company in the Second Judicial District of Nevada seeking declaratory relief and to enjoin the operation at full capacity of certain equipment to be installed by the Company for the ON Line project, until such time as Newmont completes the design, fabrication and installation of protection equipment at its power plant to protect its generator from potential adverse effects caused by the operation of the Company's equipment at full capacity. In addition, Newmont's complaint asserted a claim under the parties' interconnection agreement seeking to recover the cost of making the necessary modifications to the TS Power Plant.

A hearing on Newmont's motion for a preliminary injunction was held during the week of August 12, 2013, after which the trial court concluded that it would enter an order enjoining the Company from operating its equipment at full capacity from January 1, 2014 until approximately April 8, 2014, and from approximately June 1, 2014 to June 30, 2014 (or the time Newmont has completed the installation of its protection equipment), so as to allow installation and testing of protection equipment at the TS Power Plant. The district court issued the order in December 2013. Newmont posted the required $1 million bond and subsequently filed a complaint with the FERC to address the issue of who will pay for the protection equipment and its installation at the TS Power Plant. In April 2014, the FERC issued an order directing the Company to pay the costs of studies relating to subsynchronous resonance conducted by Newmont and the installation of the protection equipment at the TS Power Plant. The Company has estimated the costs to be $11 million and recorded the related accruals as of June 30, 2014. The costs are a component of the ON Line construction costs and are shared between the Company and Nevada Power at 5% and 95%, respectively. The protection equipment has been installed at the TS Power Plant and the Sierra Pacific facilities are now operating at full capacity. Accordingly, the $1 million bond posted by Newmont has been released. Newmont is also seeking recovery of legal fees associated with litigating this matter. At this time, the Company does not have sufficient information to assess the impact of the legal fees Newmont is seeking.

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.

To date, six subrogation lawsuits and two 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). One of the individual claimant lawsuits identifies six plaintiffs, while the other individual claimant lawsuit purports to be brought on behalf of a class of similarly affected individuals within the fire perimeter who suffered damage or loss of use of their property as a result of the Caughlin Fire and the evacuation order associated with it.

All of the cases have been consolidated before a single judge in Washoe County, Nevada. The court has not yet entered a scheduling order in this case. In July 2014, the Company reached a settlement with the Plaintiffs in the six subrogation lawsuits identified above, which did not have a material impact to the Company. At this time, management cannot assess or predict what the impact or outcome of the two individual claimant lawsuits may be, or what, if any, other litigation may be brought on this matter.

(9) Segment Information

The Company has identified two reportable operating segments: electric and natural gas. The electric segment derives most of its revenue from retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The natural gas segment derives most of its revenue from 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 electric and 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.

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.

The following tables provide information on a reportable segment basis (in millions):



	Three-Month Period							Six-Month Period
	Ended June 30, 2014							Ended June 30, 2014
			Natural							Natural
	Electric		Gas		Total			Electric		Gas		Total
Operating revenue	$	179	$	21	$	200		$	356	$	65	$	421
Cost of fuel, energy and capacity	86		—		86			166		—		166
Natural gas purchased for resale	—		12		12			—		41		41
Gross margin	$	93	$	9	102			190		24		214

Operating and maintenance expense					39							73
Depreciation and amortization					26							52
Property and other taxes					6							12
Interest expense, net of allowance for debt funds					14							29
Allowance for equity funds					(1		)					(2		)
Other, net					(3		)					(5		)
Income before income tax expense					$	21						$	55



	Three-Month Period							Six-Month Period
	Ended June 30, 2013							Ended June 30, 2013
			Natural							Natural
	Electric		Gas		Total			Electric		Gas		Total
Operating revenue	$	174	$	15	$	189		$	346	$	49	$	395
Cost of fuel, energy and capacity	70		—		70			132		—		132
Natural gas purchased for resale	—		6		6			—		24		24
Gross margin⁽¹⁾	$	104	$	9	113			214		25		239

Operating and maintenance expenses					48							96
Depreciation and amortization					27							52
Property and other taxes					7							13
Merger-related expenses					4							4
Interest expense, net of allowance for debt funds					16							32
Allowance for equity funds					—							(1		)
Other, net					(5		)					(7		)
Income before income tax expense					$	16						$	50


(1)	Energy efficiency program costs were reclassified from gross margin to operating and maintenance expenses for presentation purposes.



	As of
	June 30,		December 31,
	2014		2013
Total assets:
Electric	$	2,982	$	2,957
Natural gas	339		335
Other⁽¹⁾	88		77
Total assets	$	3,409	$	3,369


(1)	Consists principally of cash and cash equivalents.

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 2014 and 2013

Net income for second quarter of 2014 was $14 million, an increase of $3 million, or 27%, and for the first six months of 2014 was $36 million, an increase of $3 million, or 9%, as compared to 2013.

Electric Gross Margin



	Second Quarter										First Six Months
	2014		2013		Change						2014		2013		Change
Gross margin (in millions):
Operating revenue	$	179	$	174	$	5		3		%	$	356	$	346	$	10		3		%
Cost of fuel, energy and capacity	86		70		16			23			166		132		34			26
Gross margin	$	93	$	104	$	(11	)	(11	)		$	190	$	214	$	(24	)	(11	)

Sales (GWh):
Residential	484		494		(10		)	(2	)	%	1,078		1,123		(45		)	(4	)	%
Commercial	761		766		(5		)	(1	)		1,413		1,417		(4		)	—
Industrial	730		724		6			1			1,417		1,391		26			2
Other	4		4		—			—			8		8		—			—
Total retail	1,979		1,988		(9		)	—			3,916		3,939		(23		)	(1	)
Wholesale	134		272		(138		)	(51	)		343		472		(129		)	(27	)
Total sales	2,113		2,260		(147		)	(7	)		4,259		4,411		(152		)	(3	)

Average number of retail customers (in thousands)	330		327		3			1		%	330		327		3			1		%

Average retail revenue per MWh	$	82.34	$	80.56	$	1.78		2		%	$	82.74	$	80.38	$	2.36		3		%

Heating degree days	459		489		(30		)	(6	)	%	2,319		2,774		(455		)	(16	)	%
Cooling degree days	259		263		(4		)	(2	)	%	259		263		(4		)	(2	)	%

Sources of energy (GWh):
Coal	492		312		180			58		%	947		650		297			46		%
Natural gas	985		790		195			25			1,894		1,598		296			19
Total energy generated	1,477		1,102		375			34			2,841		2,248		593			26
Energy purchased	671		1,149		(478		)	(42	)		1,481		2,254		(773		)	(34	)
Total	2,148		2,251		(103		)	(5	)		4,322		4,502		(180		)	(4	)

Electric gross margin decreased $11 million, or 11%, for the second quarter of 2014 compared to 2013 due to:


•	$11 million in higher revenue as a result of the 2013 general rate case effective January 1, 2014;


•	$1 million in lower net residential usage, primarily due to a decrease in heating degree days;


•	$1 million in lower energy efficiency implementation rate revenue; and


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

The decrease in gross margin was partially offset by:


•	$2 million in higher wholesale revenue due to higher natural gas prices; and


•	$1 million in higher transmission revenue.

Electric gross margin decreased $24 million, or 11%, for the first six months of 2014 compared to 2013 due to:


•	$21 million in higher revenue as a result of the 2013 general rate case effective January 1, 2014;


•	$3 million in lower net residential usage, primarily due to a decrease in heating degree days;


•	$3 million in lower energy efficiency implementation rate revenue; and


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

The decrease in gross margin was partially offset by:


•	$3 million in higher wholesale revenue due to higher natural gas prices;


•	$1 million in higher transmission revenue; and


•	$1 million due to customer growth.

Natural Gas Gross Margin



	Second Quarter										First Six Months
	2014		2013		Change						2014		2013		Change
Gross margin (in millions):
Operating revenue	$	21	$	15	$	6		40		%	$	65	$	49	$	16		33		%
Natural gas purchased for resale	12		6		6			100			41		24		17			71
Gross margin	$	9	$	9	$	—		—			$	24	$	25	$	(1	)	(4	)

Sales (Dth):
Residential	1,234		1,205		29			2		%	4,533		5,341		(808		)	(15	)	%
Commercial	622		611		11			2			2,381		2,687		(306		)	(11	)
Industrial	281		263		18			7			788		796		(8		)	(1	)
Total retail	2,137		2,079		58			3			7,702		8,824		(1,122		)	(13	)

Average number of retail customers (in thousands)	156		154		2			1		%	156		154		2			1		%
Average revenue per retail Dth sold	$	9.72	$	6.74	$	2.98		44		%	$	8.30	$	5.39	$	2.91		54		%
Average cost of natural gas per retail Dth sold	$	5.62	$	2.88	$	2.74		95		%	$	5.32	$	2.72	$	2.60		96		%
Heating degree days	459		489		(30		)	(6	)	%	2,319		2,774		(455		)	(16	)	%

Natural gas gross margin decreased $1 million, or 4%, for the first six months of 2014 compared to 2013 primarily due to a decrease in heating degree days.

Operating and maintenance expense decreased $9 million, or 19%, for the second quarter of 2014 compared to 2013 primarily due to:


•	$3 million higher regulatory credits related to advanced meter technology and retirement of meters;


•	$3 million in lower demand side management program amortization;


•	$2 million in lower compensation and employee benefits expense;


•	$2 million in lower regulatory expense and amortization;


•	$1 million in lower energy efficiency program costs, which are fully recovered in operating revenue; and


•	$1 million in lower maintenance expense at the Tracy Generating Station.

The decrease in operating and maintenance expense was partially offset by $3 million in higher costs related to relinquishing an insurance claim for a previously sold asset.

Operating and maintenance expense decreased $23 million, or 24%, for the first six months of 2014 compared to 2013 primarily due to:


•	$7 million in lower salaries, stock compensation, employee benefits and office expense;


•	$6 million in higher regulatory credits related to NV Energize and retirement of meters;


•	$5 million in lower demand side management program amortization;


•	$3 million in lower regulatory expense and amortization;


•	$2 million in lower energy efficiency program costs, which are fully recovered in operating revenues;


•	$2 million in lower maintenance expense at the Tracy and Fort Churchill Generating Stations; and


•	$1 million in lower outside consulting services.

The decrease in operating and maintenance expense was partially offset by $3 million in higher costs related to relinquishing an insurance claim for a previously sold asset.

Merger-related expense decreased $4 million for both the second quarter and for the first six months of 2014 compared to 2013 due to costs incurred related to the merger of BHE and NV Energy in 2013.

Interest expense, net of allowance for debt funds decreased $2 million, or 13%, for the second quarter and $3 million, or 9%, for the first six months of 2014 compared to 2013 due to lower interest expense as a result of using the proceeds from issuing lower cost debt in August 2013 to repay higher cost debt. Interest expense, net of allowance for debt funds, for the second quarter of 2014 also decreased due to $1 million in lower debt amortization, partially offset by higher interest expense on regulatory items.

Allowance for equity funds increased $1 million for the second quarter and increased $1 million for the first six months of 2014 compared to 2013 primarily due to an increase in construction activity.

Other, net decreased $2 million, or 40%, for the second quarter and $2 million, or 29%, for the first six months of 2014 compared to 2013 due to a $2 million insurance reimbursement received in 2013 and $1 million in gains recognized in 2013 related to the sale of property, partially offset by $1 million for the second quarter and $2 million for the first six months of 2014 compared to 2013 in higher carrying charges related to the 2013 general rate case.

Income tax expense increased $2 million, or 40%, for the second quarter of 2014 compared to 2013 and the effective tax rates were 33% for 2014 and 31% for 2013. The increase in income tax expense was primarily due to higher pre-tax book income.

Income tax expense increased $2 million, or 12%, for the first six months of 2014 compared to 2013 and the effective tax rates were 35% for 2014 and 34% for 2013. The increase in income tax expense was primarily due to higher pre-tax book income.

Liquidity and Capital Resources

As of June 30, 2014, the Company's total net liquidity was $333 million consisting of $83 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, 2014 and 2013 were $104 million and $108 million, respectively. The change was primarily due to increased coal purchases, payment of a transmission deposit and receipt of insurance proceeds in 2013, partially offset by a decrease in deferred energy refunds to customers, an increase in collections from customers as a result of increased energy rates and timing of short-term incentive payments.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2014 and 2013 were $(88) million and $(57) million, respectively. The change was due to increased capital expenditures for various base capital projects and reduced contributions in aid of construction.

Financing Activities

Net cash flows from financing activities for the six-month periods ended June 30, 2014 and 2013 were $– million and $(20) million, respectively. The change was due to a decrease in dividends paid.

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, 2014, the Company has financing authority from the PUCN consisting of authority 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, 2014.

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.

Forecasted capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, are approximately $195 million for the year ended December 31, 2014 and are as follows (in millions):



	2014

Generation development	$	43
Distribution	100
Transmission system investment	10
Other	42
Total	$	195

Contractual Obligations

As of June 30, 2014, 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, 2013.

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, 2013, and new regulatory matters occurring in 2014.

NV Energy has announced plans to join the energy imbalance market ("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 resources, more effectively integrate renewables and enhance reliability through improved situational awareness and responsiveness. In today's environment, utilities in the west outside the California Independent System Operator ("California ISO") rely upon a combination of automated and manual dispatch within the hour to balance generation and load to maintain reliable supply and have limited capability to transact within the hour outside their own borders. In contrast, the EIM will optimize and automate five-minute dispatch of generation to serve load across the state and the California ISO footprint. The EIM is voluntary and available to all balancing authorities in the Western United States. Benefits to customers are expected to increase as more entities join and the footprint grows bringing incremental generation and load diversity. In April 2014, the Company filed an application to amend its portfolio optimization procedures contained in the PUCN-approved energy supply plan for the remaining action period of 2016. The PUCN's final order approving the merger between BHE and NV Energy stipulated that the Company would obtain PUCN authorization prior to participating in an EIM. The amendment reflects the Company's participation in the EIM that is being established by the California ISO.

The filing requests the PUCN to determine that the amended energy supply plan balances the objectives of minimizing the cost of supply and retail price volatility, maximizes the reliability of supply over the remaining term of the plan, optimizes the value of the overall supply portfolio of the Company for the benefit of bundled retail customers and does not contain any features or mechanisms that the PUCN finds would impair the restoration or the creditworthiness of the Company. A hearing on the application was held in July 2014, and an order is expected in August 2014. In April 2014 the California ISO filed the Implementation Agreement entered into by the Company and the California ISO. The Implementation Agreement provides the mechanism by which the Company will compensate the California ISO for its share of the costs to upgrade systems, software licenses and other configuration activities. The Implementation Agreement was approved by the FERC in June 2014.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign 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, local and international 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 forecasted 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, 2013.

Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in State Implementation Plans ("SIPs"), which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA.

Mercury and Air Toxics Standards

The Clean Air Mercury Rule ("CAMR"), issued by the EPA in March 2005, was the United States' first attempt to regulate mercury emissions from coal-fueled generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") in February 2008. In March 2011, the EPA proposed a new rule that would require coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards rather than a cap-and-trade system. The final rule, Mercury and Air Toxics Standards ("MATS"), was published in the Federal Register in February 2012, with an effective date of April 16, 2012, and requires that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources are required to comply with the new standards by April 16, 2015. Individual sources may be granted up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The Company believes that its emissions reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators, are consistent with the EPA's MATS and will support the Company's ability to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. The Company will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the final rule's standards, which may include retiring certain units.

Incremental costs to install and maintain emissions control equipment at the Company's coal-fueled generating facilities and any requirement to shut down what have traditionally been low cost coal-fueled generating facilities will likely increase the cost of providing service to customers. In addition, numerous lawsuits were filed against the MATS in the D.C. Circuit. In April 2014, the D.C. Circuit upheld the MATS requirements.

Climate Change

In June 2014, the EPA released proposed regulations to address greenhouse gas 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 the EPA's proposal, Nevada may utilize 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 is expected to reduce carbon dioxide emissions in the power sector to 30% below 2005 levels by 2030. The EPA is taking comment on its proposal until October 16, 2014 and is scheduled to issue final rules in June 2015. States are required to submit implementation plans by June 2016, but they may request an extension to June 2017, or June 2018 if they plan to participate in a regional compliance program. The impacts of the proposal on the Company cannot be determined until the EPA finalizes the proposal and Nevada develops its implementation plan. The Company has historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of its generating fleet to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

Water Quality Standards

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. In July 2004, the EPA established significant new technology-based performance standards for existing electricity generating facilities that take in more than 50 million gallons of water per day. These rules were aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the United States Court of Appeals for the Second Circuit ("Second Circuit") remanded almost all aspects of the rule to the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to conduct further proceedings consistent with its opinion.

In June 2013, the EPA published proposed effluent limitation guidelines and standards for the steam electric power generating sector. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions have changed the effluent discharged from coal- and natural gas-fueled generating facilities. While the EPA expected the final rule to be published in May 2014, the final rule is now scheduled for release by September 30, 2015. It is likely that the new guidelines will impose more stringent limits on wastewater discharges from coal-fueled generating facilities and ash and scrubber ponds. However, until the revised guidelines are finalized, the Company cannot predict the impact on its generating facilities.

In April 2014, the EPA and the United States Army Corps of Engineers issued a joint proposal to address "Waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. As currently proposed, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits will be required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. The public comment period has been extended on the proposal to October 20, 2014. Until the rule is finalized, the Company cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs, or increased requirements for compensatory mitigation.

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 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 June 30, 2014, 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, 2014, the Company would have been required to post $15 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, 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, 2013. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2013.

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, 2013. The Company's exposure to market risk and its management of such risk has not changed materially since December 31, 2013.

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, 2014 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, 2013.


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)



Dated:	August 1, 2014	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Senior Vice President and Chief Financial Officer
		(principal financial and accounting officer)

EXHIBIT INDEX


Exhibit No.	Description


10.1	$250,000,000 Amended and Restated Credit Agreement, dated as of June 27, 2014, among Sierra Pacific Power Company, as borrower, the Initial Lenders, Wells Fargo Bank, National Association, as administrative agent and swingline lender and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Sierra Pacific Power Company Current Report on Form 8-K dated June 27, 2014).


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, 2014, 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 1, 2014

Attached files

SIERRA PACIFIC POWER CO Reports