UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2014March 31, 2015

or

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

For the transition period from _____ to _____
Commission File Number Exact name of registrant as specified in its charter; State or other jurisdiction of incorporation or organization IRS Employer Identification No.
000-52378 NEVADA POWER COMPANY 88-0420104
  (A Nevada Corporation)  
  6226 West Sahara Avenue  
  Las Vegas, Nevada 89146  
  702-402-5000  
     
  Securities registered pursuant to Section 12(b) of the Act: None  
  Securities registered pursuant to Section 12(g) of the Act:  
  Common Stock, $1.00 stated value  

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes T No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No T

All shares of outstanding common stock of Nevada Power Company are held by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of October 31, 2014,April 30, 2015, 1,000 shares of common stock, $1.00 stated value, were outstanding.





TABLE OF CONTENTS

PART I
Item 1.
Financial Statements
1
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
14
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
2221
Item 4.
Controls and Procedures
2321
   
PART II
   
Item 1.
Legal Proceedings
2422
Item 1A.
Risk Factors
2422
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
2422
Item 3.
Defaults Upon Senior Securities
2422
Item 4.
Mine Safety Disclosures
2422
Item 5.
Other Information
2422
Item 6.
Exhibits
2422
Signatures

2523
Exhibit Index
 
2624


i


Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 2 through 4, and Part II - Items 1 through 6, the following terms have the definitions indicated.
Nevada Power Company and Related Entities
   
Company Nevada Power Company and its subsidiaries
BHE Berkshire Hathaway Energy Company
NV Energy NV Energy, Inc.
Berkshire HathawayBerkshire Hathaway Inc.
Sierra Pacific Sierra Pacific Power Company, an electric and natural gas utility wholly owned by NV Energy
Clark Generating Station1,103-megawatt generating facility in Nevada
Goodsprings5-megawatt waste heat recovery facility in Nevada
Harry Allen Generating Station628-megawatt generating facility in Nevada
Higgins Generating Station530-megawatt generating facility in Nevada
Lenzie Generating Station1,102-megawatt generating facility in Nevada
Las Vegas Generating Station272-megawatt generating facility in Nevada
Navajo Generating Station 2,250-megawatt generating facility in Arizona
Nellis Generating Station15-megawatt generating facility under construction in Nevada
ON Line 500-kilovolt transmission line connecting the Company and Sierra Pacific
Reid Gardner Generating Station 557-megawatt257-megawatt generating facility in Nevada
Silverhawk Generating Station520-megawatt generating facility in Nevada
Sun Peak Generating Station210-megawatt generating facility in Nevada
   
Certain Industry Terms
   
AFUDC Allowance for Funds Used During Construction
California ISOCalifornia Independent System Operator Corporation
EEIREnergy Efficiency Implementation Rate
EIMEnergy Imbalance Market
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
GWh Gigawatt Hours
MW Megawatts
MWh Megawatt Hours
PUCN Public Utilities Commission of Nevada


ii


Forward-Looking Statements

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

general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including reliability and safety standards, affecting the Company's operations or related industries;
changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;
the outcome of rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company's ability to recover costs in rates in a timely manner;
changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and distributed generation measures and programs, that could affect customer growth and usage, electricity supply or the Company's ability to obtain long-term contracts with customers and suppliers;
performance 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;
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;
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.

iii



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.


iv


PART I

Item 1.    Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
Nevada Power Company
Las Vegas, Nevada

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries (the "Company") as of September 30, 2014,March 31, 2015, and the related consolidated statements of operations, for the three-month and nine-month periods ended September 30, 2014 and 2013, and of changes in shareholder's equity and cash flows for the nine-monththree-month periods ended September 30, 2014March 31, 2015 and 2013.2014. These interim financial statements are the responsibility of the Company's management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Nevada Power Company and subsidiaries as of December 31, 2013,2014, 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 March 31, 2014,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, 20132014 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.


/s/ Deloitte & Touche LLP


Las Vegas, Nevada
November 7, 2014May 1, 2015

1


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)

As ofAs of
September 30, December 31,March 31, December 31,
2014 20132015 2014
ASSETS
      
Current assets:      
Cash and cash equivalents$420
 $126
$41
 $220
Accounts receivable, net427
 227
247
 243
Inventories74
 73
90
 88
Regulatory assets65
 81
5
 57
Deferred income taxes90
 152
139
 145
Other current assets42
 39
45
 32
Total current assets1,118
 698
567
 785
      
Property, plant and equipment, net6,917
 6,992
6,994
 7,003
Regulatory assets969
 1,057
1,056
 1,069
Other assets84
 88
68
 78
      
Total assets$9,088
 $8,835
$8,685
 $8,935
      
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:      
Accounts payable$220
 $240
$180
 $212
Accrued interest42
 61
39
 60
Accrued property, income and other taxes40
 29
Accrued employee expenses15
 6
Accrued property and other taxes25
 30
Regulatory liabilities42
 74
37
 40
Short-term debt30
 —
Current portion of long-term debt261
 22
226
 264
Customer deposits and other105
 74
Customer deposits57
 55
Other current liabilities66
 36
Total current liabilities725
 506
660
 697
      
Long-term debt3,306
 3,555
3,099
 3,312
Regulatory liabilities322
 312
329
 326
Deferred income taxes1,365
 1,298
1,421
 1,414
Other long-term liabilities243
 274
264
 298
Total liabilities5,961
 5,945
5,773
 6,047
      
Commitments and contingencies (Note 9)
 
Commitments and contingencies (Note 8)
 
      
Shareholder's equity:      
Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding—
 —
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding—
 —
Other paid-in capital2,308
 2,308
2,308
 2,308
Retained earnings822
 586
607
 583
Accumulated other comprehensive loss, net(3) (4)(3) (3)
Total shareholder's equity3,127
 2,890
2,912
 2,888
      
Total liabilities and shareholder's equity$9,088
 $8,835
$8,685
 $8,935
      
The accompanying notes are an integral part of the consolidated financial statements.


2


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

Three-Month Periods Nine-Month PeriodsThree-Month Periods
Ended September 30, Ended September 30,Ended March 31,
2014 2013 2014 20132015 2014
          
Operating revenue$867
 $784
 $1,879
 $1,690
$459
 $417
          
Operating costs and expenses:          
Cost of fuel, energy and capacity368
 291
 855
 642
226
 203
Operating and maintenance expense113
 113
 282
 316
Operating and maintenance76
 82
Depreciation and amortization69
 65
 204
 195
74
 66
Property and other taxes10
 8
 31
 28
9
 11
Merger-related expenses—
 5
 —
 14
Total operating costs and expenses560
 482
 1,372
 1,195
385
 362
          
Operating income307
 302
 507
 495
74
 55
          
Other income (expense):          
Interest expense, net of allowance for debt funds(51) (54) (154) (160)
Interest expense(46) (51)
Allowance for borrowed funds1
 —
Allowance for equity funds—
 2
 —
 6
1
 —
Other, net10
 5
 20
 13
7
 6
Total other income (expense)(41) (47) (134) (141)(37) (45)
          
Income before income tax expense266
 255
 373
 354
37
 10
Income tax expense98
 90
 137
 125
13
 4
Net income$168
 $165
 $236
 $229
$24
 $6
          
The accompanying notes are an integral part of these consolidated financial statements.The accompanying notes are an integral part of these consolidated financial statements.  The accompanying notes are an integral part of these consolidated financial statements.


3


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)

         Accumulated           Accumulated  
     Other   Other Total     Other   Other Total
 Common Stock Paid-in Retained Comprehensive Shareholder's Common Stock Paid-in Retained Comprehensive Shareholder's
 Shares Amount Capital Earnings Loss, Net Equity Shares Amount Capital Earnings Loss, Net Equity
Balance at December 31, 2012 1,000
 $—
 $2,308
 $619
 $(4) $2,923
Net income —
 —
 —
 229
 —
 229
Dividends declared —
 —
 —
 (105) —
 (105)
Other —
 —
 —
 (1) —
 (1)
Balance at September 30, 2013 1,000
 $—
 $2,308
 $742
 $(4) $3,046
            
Balance at December 31, 2013 1,000
 $—
 $2,308
 $586
 $(4) $2,890
Balance, December 31, 2013 1,000
 $—
 $2,308
 $586
 $(4) $2,890
Net income —
 —
 —
 236
 —
 236
 —
 —
 —
 6
 —
 6
Other —
 —
 —
 —
 1
 1
 —
 —
 —
 —
 1
 1
Balance at September 30, 2014 1,000
 $—
 $2,308
 $822
 $(3) $3,127
Balance, March 31, 2014 1,000
 $—
 $2,308
 $592
 $(3) $2,897
            
Balance, December 31, 2014 1,000
 $—
 $2,308
 $583
 $(3) $2,888
Net income —
 —
 —
 24
 —
 24
Balance, March 31, 2015 1,000
 $—
 $2,308
 $607
 $(3) $2,912
                        
The accompanying notes are an integral part of these consolidated financial statements.


4


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

Nine-Month PeriodsThree-Month Periods
Ended September 30,Ended March 31,
2014 20132015 2014
      
Cash flows from operating activities:      
Net income$236
 $229
$24
 $6
Adjustments to reconcile net income to net cash flows from operating activities:      
Loss on nonrecurring items15
 —
Gain on nonrecurring items(3) —
Depreciation and amortization204
 195
74
 66
Allowance for equity funds—
 (6)(1) —
Deferred income taxes and amortization of investment tax credits137
 126
13
 4
Amortization of deferred energy16
 13
Deferred energy39
 (2)
Amortization of other regulatory assets100
 19
10
 12
Other, net31
 34
(14) 5
Changes in other operating assets and liabilities:      
Accounts receivable and other assets(293) (224)(25) (32)
Inventories(1) 7
(2) 3
Accounts payable and other liabilities22
 20
(39) (42)
Net cash flows from operating activities451
 400
92
 33
      
Cash flows from investing activities:      
Capital expenditures(147) (138)(68) (58)
Contributions in aid of construction and customer advances5
 9
Proceeds from sale of asset4
 —
Other, net—
 2
10
 —
Net cash flows from investing activities(147) (136)(49) (49)
      
Cash flows from financing activities:      
Repayment of long-term debt(10) (104)
Dividends paid—
 (105)
Proceeds from issuance of short-term debt, net of costs75
 —
Repayments of long-term debt(252) (11)
Repayments of short-term debt(45) —
Net cash flows from financing activities(10) (209)(222) (11)
      
Net change in cash and cash equivalents294
 55
(179) (27)
Cash and cash equivalents at beginning of period126
 201
220
 126
Cash and cash equivalents at end of period$420
 $256
$41
 $99
      
The accompanying notes are an integral part of these consolidated financial statements.


5


NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)    Organization and Operations

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

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2014March 31, 2015 and for the three- and nine-monththree-month periods ended September 30, 2014March 31, 2015 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.2014. The results of operations for the three- and nine-month periodsthree-month period ended September 30, 2014March 31, 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, 20132014 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the nine-monththree-month period ended September 30, 2014.March 31, 2015.

(2)    New Accounting Pronouncements

In May 2014,April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09,2015-03, which createsamends 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. 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. 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.


6


(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
As of  As of
September 30, December 31,Depreciable Life March 31, December 31,
2014 2013 2015 2014
Utility plant in-service:       
Generation$4,169
 $3,789
25 - 80 years $4,054
 $4,034
Distribution2,999
 2,936
20 - 65 years 3,033
 3,018
Transmission1,751
 1,743
45 - 65 years 1,765
 1,757
General and intangible plant683
 645
General intangible plant5 - 65 years 679
 669
Utility plant in-service9,602
 9,113
 9,531
 9,478
Accumulated depreciation and amortization(2,748) (2,217) (2,653) (2,599)
Utility plant in-service, net6,854
 6,896
 6,878
 6,879
Other non-regulated, net of accumulated depreciation and amortization4
 3
5 - 65 years 4
 4
6,858
 6,899
 6,882
 6,883
Construction work-in-progress59
 93
 112
 120
Property, plant and equipment, net$6,917
 $6,992
 $6,994
 $7,003

(4)    Regulatory Matters

Deferred Energy Efficiency Implementation Rates

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'sNevada ("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 merger between BHE and NV EnergyMerger stipulated that the Company willwould not seek recovery of any lost revenue for calendar year 2014 in an amount that exceedsexceeded 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 implementation rate.program rates. In June 2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate,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 energy efficiency implementation rate will beEEIR was effective from July through December 2014, and will resetset on January 1, 2015 and remainremains 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 rateEEIR revenue collected. As a result, the Company has deferred recognition of energy efficiency implementation rateEEIR revenue collected and has recorded a liability of $10$11 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of September 30, 2014.March 31, 2015.


7


General Rate Case

In May 2014, the Company filed a general rate case with the PUCN. In July 2014, the Company made its certification filing, which requested incremental annual revenue relief in the amount of $38 million, or an average price increase of 2%. In October 2014, Nevada Powerthe Company reached a settlement agreement with certain parties agreeing to a zero increase in the revenue requirement. In October 2014, the PUCN approved and issued an order in the general rate case filing that agreed toaccepted the settlement. The order provides for increases in the fixed-monthly service charge for customers with a corresponding decrease in the base tariff general rate effective January 1, 2015. As a result of the order, the Company recorded $15 million in asset impairments related to property, plant and equipment and $5 million of regulatory asset impairments, which are included in operating and maintenance expense on the Consolidated Statements of Operations for the three- and nine-month periodsyear ended September 30,December 31, 2014. Additionally, the Company recorded a $5 million gain in other, net on the Consolidated Statement of Operations for the three- and nine-month periodsyear ended September 30,December 31, 2014 related to the disposition of property. In October 2014, a party filed a petition for reconsideration of the PUCN order. The Company is preparing a response toIn November 2014, the reconsideration.PUCN granted the petition for reconsideration and reaffirmed the order issued in October 2014.

7



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

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

In September 2014, the Company, along with Sierra Pacific, filed an unopposed settlement offer with the FERC on behalf of NV Energy and the intervening parties providing rate relief of $4 million. The settlement offer would resolve all outstanding issues related to this case. In addition, a preliminary order from the administrative law judge granting the motion for interim rate relief was issued, which authorizes the Company to institute the interim rates effective September 1, 2014, and begin billing transmission customers under the settlement rates for service provided on and after that date. These will remain in effect pending the FERC's approval. As of September 30, 2014, the Company accrued $10 million for amounts subject to rate refund, which is included in customer deposits and other on the Consolidated Balance Sheets. In October 2014,January 2015, the FERC judge certifiedapproved the settlement and referred to the FERC for final approval. Once the FERC approves the Offer of Settlement, the Company will refund amounts thatrefunds were billed to the FERC transmission customers subject to refund.issued.

(5)    Recent Financing Transactions

Credit Facility

In June 2014, the Company amended its $500 million secured credit facility expiring in March 2017, reducing the amount available to $400 million and 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"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.loss, net.

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
 As of
 September 30, December 31,
 2014 2013
Qualified Pension Plan:   
Other assets$8
 $13
    
Non-Qualified Pension Plans:   
Accrued employee expenses(4) (4)
Other long-term liabilities(5) (8)
    
Other Postretirement Plans:   
Other long-term liabilities(8) (7)
 As of
 March 31, December 31,
 2015 2014
Qualified Pension Plan -   
Other long-term liabilities(24) (23)
    
Non-Qualified Pension Plans:   
Other current liabilities(1) (1)
Other long-term liabilities(9) (9)
    
Other Postretirement Plans -   
Other long-term liabilities1
 1


8


(7)(6)     Risk Management and Hedging Activities

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

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

There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Note 87 for additional information on derivative contracts.

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

 Customer Other   Other Other  
 Deposits and Long-term   Current Long-term  
 Other Liabilities Total Liabilities Liabilities Total
As of September 30, 2014      
As of March 31, 2015      
Commodity liabilities(1)
 $(8) $(21) $(29) $(11) $(21) $(32)
            
As of December 31, 2013      
As of December 31, 2014      
Commodity liabilities(1)
 $(9) $(38) $(47) $(9) $(21) $(30)

(1)
The Company's commodity derivatives not designated as hedging contracts are included in regulated rates and as of September 30, 2014March 31, 2015 and December 31, 2013,2014, a regulatory asset of $29$32 million and $47$30 million,, respectively, was recorded related to the derivative liability of $29$32 million and $47$30 million, respectively.

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contracts with indexed and fixed price terms that comprise the mark-to-market values as of (in millions):
Unit of September 30, December 31,Unit of March 31, December 31,
Measure 2014 2013Measure 2015 2014
Electricity salesMegawatt hours (3) (4)Megawatt hours (3) (3)
Natural gas purchasesDecatherms 133
 118
Decatherms 161
 115


9


Credit Risk

The Company extends unsecuredis exposed to counterparty credit torisk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants in conjunction with its wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations.participants. Credit risk may be concentrated to the extent that one or more groups ofthe Company's counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may defaultand due to circumstances relating directly to it, but alsodirect and indirect

9


relationships among the risk thatcounterparties. Before entering into a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship withtransaction, the counterparty.

The Company analyzes the financial condition of each significant wholesale counterparty, before entering into any transactions, establishesestablish limits on the amount of unsecured credit to be extended to each counterparty and evaluatesevaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate exposure to the financial risks of wholesale counterparties,counterparty credit risk, the Company enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtainsobtain third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed fees for delayed payments. If required, the Company exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts may either specifically provide rights to demand cash or other security in the event of a credit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2014,March 31, 2015, credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features was $5$6 million and $4 million as of March 31, 2015 and December 31, 2014, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

(8)(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. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 - Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

The following table presents the Company's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 Input Levels for Fair Value Measurements  
 Level 1 Level 2 Level 3 Total
As of March 31, 2015       
Assets - investment funds$9
 $—
 $—
 $9
        
Liabilities - commodity derivatives$—
 $—
 $(32) $(32)
        
As of December 31, 2014       
Assets - investment funds$20
 $—
 $—
 $20
        
Liabilities - commodity derivatives$—
 $—
 $(30) $(30)


10


The Company's commodity
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts are valuedis estimated using a market approach that usesunadjusted quoted forward commodity prices for similar assetsidentical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and liabilities, whichcommercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid-pointmid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Interest rate swaps are valued using a financial model which utilizes observable inputs for similar instruments based primarily on market price curves. The determination of the fair value for derivative instrumentscontracts not only includes counterparty risk, but also the impact of the Company's nonperformance risk on its liabilities, which as of September 30, 2014March 31, 2015 and December 31, 2013,2014, had an immaterial impact to the fair value of its derivative instruments.contracts. As such, the Company considers its commodity derivative contracts to be valued using Level 3 inputs. Refer to Note 6 for further discussion regarding the Company's risk management and hedging activities.

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

The following table reconciles the beginning and ending balances of the Company's commodity derivative liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
Three-Month Period
Three-Month Period Nine-Month PeriodEnded March 31,
Ended September 30, 2014 Ended September 30, 20142015 2014
Beginning balance$(33) $(47)$(30) $(47)
Changes in fair value recognized in regulatory assets—
 12
(4) 12
Purchases1
 —
Settlements3
 6
2
 —
Ending balance$(29) $(29)$(32) $(35)

The Company's long-term debt is carried at cost on the Consolidated Financial Statements.Balance Sheets. The fair value of the Company's long-termlong‑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-termlong‑term debt (in millions):
 As of September 30, 2014 As of December 31, 2013
 Carrying Fair Carrying Fair
 Value Value Value Value
        
Long-term debt$3,067
 $3,678
 $3,071
 $3,596
 As of March 31, 2015 As of December 31, 2014
 Carrying Fair Carrying Fair
 Value Value Value Value
        
Long-term debt$2,818
 $3,476
 $3,066
 $3,712

(9)(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.

11



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

Accelerating the plan to retire 800 MWs of coal plants, starting as soon as December 31, 2014;
Replacement of such coal plants by issuing requests for proposals for the procurement of 300 MWs from renewable facilities;
Construction or acquisition and ownership of 50 MWs of electric generating capacity from renewable facilities;
Construction or acquisition and ownership of 550 MWs of additional electric generating capacity; and
Assuring regulatory procedures that protect reliability and supply and address financial impacts on customer and utility.


11


In February 2014, the PUCN issued a final order approving draft regulations, subject to review by a Nevada Legislative commission, which became effective March 2014. In May 2014, the Company filed its EmissionEmissions Reduction Capacity Replacement Plan ("ERCR Plan") proposing,in compliance with Senate Bill No. 123 ("SB 123") enacted by the 2013 Nevada Legislature. The filing proposed, among other items, the retirement of Reid Gardner Generating Station units 1, 2 and 3 in 2014 and unit 4 in 2017; the elimination of the Company's ownership interest in Navajo Generating Station in 2019; and a plan to replace the generating capacity being retired, as required by Senate Bill No.SB 123. The ERCR Plan includes the issuance of requests for proposals for 300-MW of renewable energy to be issued between 2014 and 2016; the acquisition of a 274-MW272-MW natural gas co-generating facility in 2014; the acquisition of a 222-MW210-MW natural gas peaking facility in 2014; the construction of a 15-MW solar photovoltaic facility expected to be placed in-service in 2015; and the construction of a 200-MW solar photovoltaic facility expected to be placed in-service in 2016. In the second quarter of 2014, the Company executed various contractual agreements to fulfill the proposed ERCR Plan, which are subject to the PUCN approval. The PUCN issued an order dated October 28, 2014 removing the 200-MW solar photovoltaic facility proposed by the Company from the ERCR Plan but accepting the remaining requests. Under Nevada law, the Company may elect to accept the plan as modified by the PUCN, file a motion for reconsideration or withdraw the filing from consideration and file a new ERCR Plan.  In November 2014, the Company filed a requestpetition for reconsideration, but in December 2014, the PUCN upheld the original order from October 2014 with respect to extendmaterial matters. In December 2014, the deadlineCompany filed its acceptance of the modifications to make its election.  The Company cannot determine the outcome of this proceeding at this time.ERCR Plan.

Reid Gardner GeneratingGeneration Station

In October 2011, the Company received a request for information from the Environmental Protection Agency Region 9 under Section 114 of the Clean Air Act requesting current and historical operations and capital project information for the Company's Reid Gardner Generating Station located near Moapa, Nevada. The Environmental Protection Agency's Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the Environmental Protection Agency relating to the plant. The Company completed its responseresponses to the Environmental Protection Agency during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, the Company cannot predict the impact, if any, associated with this information request.

Legal Matters

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

November 2005 Land Investors

In 2006, November 2005 Land Investors, LLC ("NLI") purchased from the United States through the Bureau of Land Management 2,675 acres of land located in North Las Vegas, Nevada. A small portion of the land is traversed by a 500 kilovolt ("kV") transmission line owned by the Company and sited pursuant to a pre-existing right-of-way grant from the Bureau of Land Management. Subsequent to NLI's purchase, a dispute arose as to whether the Company owed rent and, if it did, the amount owed to NLI under the right-of-way grant. NLI eventually "terminated" the right-of-way grant and brought claims against the Company for breach of contract, inverse condemnation and trespass. The Company counterclaimed for express condemnation of a perpetual easement over the right-of-way corridor. The matter proceeded to trial in the Eighth Judicial District Court, Clark County, Nevada ("Eighth District Court"). In September 2013, the Eighth District Court awarded NLI $1 million for unpaid rent and $5 million for inverse condemnation, plus interest and attorneys' fees, bringing the total judgment to $12 million. The Eighth District Court also found the Company was entitled to judgment in its favor on its counterclaim for condemnation of the right-of-way corridor. The Company has posted the required bond of $12 million and has appealed to the Nevada Supreme Court. Management cannot assess or predict the outcome of the case at this time.


12


Park Highlands

The Company has six other rights-of-way located on the same 2,675 acres of land located in North Las Vegas, Nevada, commonly referred to as the Park Highlands properties. NLI purportedly also terminated the other six rights‑of‑way. On January 2, 2015 KBS SOR Park Highlands, LLC ("KBS") filed a complaint in the Eighth District Court relating to one of the six rights‑of‑way, specifically the right-of-way that relates to a 230‑kV line that traverses the property. In the complaint, KBS raised the same claims previously raised by NLI in the litigation relating to the 500‑kV line. On January 9, 2015, the Company filed an action in the Eighth District Court relating to the six rights-of-way on the Park Highlands properties. This action sought a declaratory order quieting the Company's title to the rights-of-way or in the alternative condemning an easement interest in the property.

Skye Canyon

In 2005, the Bureau of Land Management sold at auction a parcel of land commonly known as the Skye Canyon properties. The property was sold subject to preexisting rights-of-way held by the Company for the placement of electric transmission and distribution facilities. On January 9, 2015, the Company filed an action in the Eighth District Court relating to 14 rights‑of‑way located within the Skye Canyon properties. The action sought a declaratory order from the court that the rights-of-way held by the Company are still valid, establish the proper rent, if any, payable by the Company and to identify the proper party to whom rent is due.

Sierra Club and Moapa Band of Paiute Indians

In August 2013, the Sierra Club and Moapa Band of Paiute Indians filed a complaint in federal district court in Nevada against the Company and the California Department of Water Resources, ("CDWR"), alleging that activities at the Reid Gardner Generating Station are causing imminent and substantial harm to the environment and that placement of coal combustion residuals at the on-site landfill constitute "open dumping" in violation of the Resource Conservation and Recovery Act. The complaint also alleges that the Reid Gardner Generating Station is engaged in the unlawful discharge of pollutants in violation of the Clean Water Act. The notice was issued pursuant to the citizen suit provisions of the Resource Conservation and Recovery Act and the Clean Water Act. CDWRthe California Department of Water Resources was named as a co-defendant in the litigation due to its prior co-ownership in Reid Gardner Generating Station unitUnit 4. The complaint seeks various injunctive remedies, assessment of civil penalties, and reimbursement of plaintiffs' attorney and legal fees and costs. In August 2014, the court dismissed without prejudice the plaintiff's amended complaint which sought civil penalties. The Company answered the complaint and has recently engaged in discussions with the plaintiffs to determine if a settlement can be reached that avoids the costs and burden of litigation. ManagementThe Company cannot assess or predict the outcome of the case at this time.


13



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 ThirdFirst Quarter of 2015 and First Nine Months of 2014 and 2013

Net income for the third quarter of 2014 was $168 million, an increase of $3 million, or 2%, as compared to 2013 due to reductions to income from energy efficiency implementation rate revenue adjustments recorded in 2013, higher retail volumes and merger-related expense in 2013, partially offset by impairment costs resulting from the settlement of the 2014 general rate case and higher depreciation and amortization.

Net income for the first nine monthsquarter of 20142015 was $236$24 million, an increase of $7$18 million, or 3%, as compared to 20132014 due to merger-related expensehigher margins from increased customer usage, growth and a rate design change from the 2014 rate case effective January 2015, changes in 2013, reductions to income from energy efficiency implementation rate revenue adjustments recorded in 2013, higher retail volumes,contingent liabilities, lower debt interest costs, and lower compensation, investor relations, bad debt and insurance costs,the gain on sale of an equity investment. These increases were partially offset by impairment costs resulting from the settlement of theON Line lease expenses, which were deferred in 2014 general rate case.but expensed in 2015 and higher depreciation and amortization costs.



14


Operating revenue and cost of fuel, energy and capacity are key drivers of the Company's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. The Company believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity, is therefore meaningful. A comparison of the Company's key operating results is as follows:
  First Quarter 
  2015 2014 Change
Gross margin (in millions):        
Operating revenue $459
 $417
 $42
10
%
Cost of fuel, energy and capacity 226
 203
 23
11
 
Gross margin $233
 $214
 $19
9
 
         
GWh sold:        
Residential 1,525
 1,465
 60
4
%
Commercial 993
 933
 60
6
 
Industrial 1,717
 1,629
 88
5
 
Other 53
 53
 —
—
 
Total retail 4,288
 4,080
 208
5
 
Wholesale 14
 5
 9
* 
Total GWh sold 4,302
 4,085
 217
5
 
         
Average number of retail customers (in thousands):        
Residential 776
 763
 13
2
%
Commercial 105
 104
 1
1
 
Industrial 2
 1
 1
* 
Total 883
 868
 15
2
 
         
Average retail revenue per MWh $104.34
 $99.89
 $4.45
4
%
         
Heating degree days 586
 668
 (82)(12)%
Cooling degree days 148
 34
 114
*%
         
Sources of energy (GWh)(1):
        
Coal 283
 1,228
 (945)(77)%
Natural gas 3,547
 2,269
 1,278
56
 
Total energy generated 3,830
 3,497
 333
10
 
Energy purchased 523
 811
 (288)(36) 
Total 4,353
 4,308
 45
1
 

*     Not meaningful
(1)GWh amounts are net of energy used by the related generating facilities.



1415


  Third Quarter  First Nine Months 
  2014 2013 Change 2014 2013 Change
Gross margin (in millions):                
Operating revenue $867
 $784
 $83
11
% $1,879
 $1,690
 $189
11
%
Cost of fuel, energy and capacity 368
 291
 77
26
  855
 642
 213
33
 
Gross margin $499
 $493
 $6
1
  $1,024
 $1,048
 $(24)(2) 
                 
Sales (GWh):                
Residential 3,675
 3,627
 48
1
% 7,436
 7,592
 (156)(2)%
Commercial 1,361
 1,329
 32
2
  3,474
 3,423
 51
1
 
Industrial 2,101
 2,078
 23
1
  5,743
 5,756
 (13)—
 
Other 56
 56
 —
—
  155
 153
 2
1
 
Total retail 7,193
 7,090
 103
1
  16,808
 16,924
 (116)(1) 
Wholesale 4
 6
 (2)(33)  10
 24
 (14)(58) 
Total sales 7,197
 7,096
 101
1
  16,818
 16,948
 (130)(1) 
                 
Average number of retail customers (in thousands) 877
 863
 14
2
% 873
 857
 16
2
%
                 
Average retail revenue per MWh $119.63
 $109.07
 $10.56
10
% $110.34
 $98.37
 $11.97
12
%
                 
Heating degree days —
 —
 —
—
% 709
 1,084
 (375)(35)%
Cooling degree days 2,246
 2,164
 82
4
  3,645
 3,658
 (13)—
 
                 
Sources of energy (GWh):                
Coal 1,171
 995
 176
18
% 3,748
 2,262
 1,486
66
%
Natural gas 4,268
 4,414
 (146)(3)  9,549
 11,542
 (1,993)(17) 
Total energy generated 5,439
 5,409
 30
1
  13,297
 13,804
 (507)(4) 
Energy purchased 2,270
 2,077
 193
9
  4,623
 4,225
 398
9
 
Total 7,709
 7,486
 223
3
  17,920
 18,029
 (109)(1) 

Gross margin increased $6$19 million, or 1%9%, for the thirdfirst quarter of 20142015 compared to 20132014 primarily due to:
$6 million due to peak hour usage;
$6 million provision for refund of energy efficiency implementation rate revenue recorded in 2013; and
$4 million due to customer growth.
The increase in gross margin was partially offset by:
$9 million in lowerhigher energy efficiency program rate revenue, which is offset in operating and maintenance expense andexpense;
$2 million lower transmission revenue.

Gross margin decreased $24 million, or 2%, for the first nine months of 2014 compared to 2013 due to:
$21 million in lower energy efficiency program rate revenue, which is offset in operating and maintenance expense and
$20 million in lower residential customer usage in 2014.
The decrease in gross margin was partially offset by:
$104 million due to customer growth;a rate design change from the 2014 general rate case effective January 1, 2015;
$4 million in higher customer usage in 2015;
$3 million in transmission revenue;revenue primarily due to increased ON Line usage; and
•$32 million due to peak hour usage.customer growth.

Operating and maintenance expense remained unchangeddecreased $6 million, or 7%, for the thirdfirst quarter of 20142015 compared to 20132014 primarily due to decreased amortizations of demand side management program costs, from:
$10 millionchanges in costs for the disallowance of energy efficiency implementation revenue in 2013;
$9 million incontingent liabilities and lower compensation costs. The decrease is partially offset by ON Line lease expense and increased energy efficiency program costs, which are fully recovered in operating revenue;revenue.and
$4 million in lower compensation costs, investor relations and insurance costs.

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The decrease in operating and maintenance expense was offset by:
$20 million of impairment costs resulting from the settlement of the 2014 general rate case and
$3 million in higher operating and maintenance costs for the Reid Gardner and Navajo Generating Stations.

Operating and maintenance expense decreased $34 million, or 11%, for the first nine months of 2014 compared to 2013 due to:
$21 million in lower energy efficiency program costs, which are fully recovered in operating revenue;
$14 million decrease in major outages and planned maintenance costs at the generating stations;
$11 million in costs for the disallowance of energy efficiency implementation revenue in 2013;
$9 million in lower compensation costs;
$7 million in lower investor relations, bad debt and insurance costs;
$3 million in lower costs associated with outside consulting services; and
$2 million in lower sales tax related to a long-term service agreement settlement.
The decrease in operating and maintenance expense was offset by:
$20 million of impairment costs resulting from the settlement of the 2014 general rate case;
$9 million in higher operating and maintenance costs for Reid Gardner Unit 4 previously shared with the former partner;
$3 million in ON Line lease payments; and
$2 million in higher transmission and distribution costs.

Depreciation and amortization increased $4$8 million, or 6%, for the third quarter and $9 million, or 5%12%, for the first nine monthsquarter of 20142015 compared to 20132014 primarily due to higher plant in-service, including ON Line being placed in-service in December 2013, and amortizationthe acquisition of Reid Gardner Unit 4.4 in 2014 and increased regulatory amortizations as a result of the 2014 general rate case effective January 1, 2015.

Merger-relatedInterest expense decreased $5 million, for the third quarter and $14 million for the first nine 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 $3 million, or 6%, for the third quarter and $6 million, or 4%10%, for the first nine monthsquarter of 20142015 compared to 2013 as a result of using cash on hand to repay existing debt in July and December 2013, interest for an assessment on a right-of-way lease in 2013 and a decrease of interest expense related to regulatory assets, partially offset by general rate case adjustments related to ON Line in 2014 and lower debt AFUDC primarily due to assets being placed in-service.

Allowance for equity funds decreased $2redemption of $250 million for the third quarterSeries L, 5.875% General and $6 million for the first nine months of 2014 compared to 2013 due to assets placed in-service, including ON Line being placed in-service in December 2013.Refunding Mortgage Notes.

Other, net increased $5 million for the third quarter and $7$1 million, or 54%17%, for the first nine monthsquarter of 20142015 compared to 20132014 primarily due to realizing a $5 million gain on the sale of property andan equity investment in March 2015, partially offset by lower interest earnedincome on regulatory items of $1 million for the third quarter and $3 million for the first nine months of 2014.deferred charges.

Income tax expense increased $8$9 million or 9%, for the third quarter and $12 million, or 10%, for the first nine monthsquarter of 20142015 compared to 20132014 and the effective tax rates were 35% for 2015 and 37% for the third quarter and first nine months of 2014 and 35% for the third quarter and first nine months of 2013.2014. The increase in income tax expense and change in effective tax rate is primarily due to higher pre-tax earnings.income before income tax expense.

Liquidity and Capital Resources

As of September 30, 2014,March 31, 2015, the Company's total net liquidity was $820$411 million consisting of $420$41 million in cash and cash equivalents and $400$370 million of revolving credit facility availability.


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Operating Activities

Net cash flows from operating activities for the nine-monththree-month periods ended September 30,March 31, 2015 and 2014 and 2013 were $451$92 million and $400$33 million, respectively. The change was primarily due to higher collections for deferred energy costs, a one-time bill credit of $15 million to retail customers refunded in 2014 in connection with the BHE Merger, lower compensation payments, lower energy efficiency program costs and higher revenue collections as a result of the 2014 general rate case effective January 1, 2015. The increase is partially offset by higher refunds to customers for energy costs in 2013, reduced operating costs, decreases inconservation and renewable energy and conservation spend, timing of short-term incentive payments, collection of prior period deferred conservation program costs, and higher collections from customer growth. The increase in net cash flows from operating activities was partially offset by increased rent payments related to the ON Line transmission use agreement and a one-time bill credit paid to retail customers in 2014 associated with the merger between BHE and NV Energy.programs.

Investing Activities

Net cash flows from investing activities for the nine-monththree-month periods ended September 30,March 31, 2015 and 2014 and 2013 were $(147) million and $(136) million, respectively. The change was$(49) million. Investing activities remained constant due to higheran increase in capital expenditures for various base capital projectsoffset by the cash received from the sale of securities and reduced contributions in aid of construction.an equity investment.

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Financing Activities

Net cash flows from financing activities for the nine-monththree-month periods ended September 30,March 31, 2015 and 2014 and 2013 were $(10)$(222) million and $(209)$(11) million, respectively. The change was due to a decrease in dividends paid and the redemptionrepayments of long-term debt, in August 2013.partially offset by proceeds from short-term borrowings.

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

Ability to Issue Debt

The Company's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2014,March 31, 2015, the Company has financing authority from the PUCN consisting of authoritythe ability to: (1) issue additional long-term debt securities of up to $725 million; (2) refinance up to $423 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion. The Company's revolving credit facility contains a financial maintenance covenant which the Company was in compliance with as of September 30, 2014.March 31, 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 Investor 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-controlpollution 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 acquisitionsacquisition of existing assets.


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Forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the year ended December 31, 20142015 are as follows (in millions):
 2014 2015
    
Generation development $210
 $118
Distribution 78
 118
Transmission system investment 13
 45
Other 57
 40
Total $358
 $321

Contractual Obligations

As of September 30, 2014,March 31, 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, 2013.2014.


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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, 2013,2014, and new regulatory matters occurring in 2014.2015.

State Regulatory Matters

The PUCN's final order approving the merger between BHE and NV EnergyMerger stipulated that the Company willwould not seek recovery of any lost revenue for calendar year 2014 in an amount that exceedsexceeded 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 implementation rate.program rates. In June 2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate,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 energy efficiency implementation rate will beEEIR was effective from July through December 2014, and will resetset on January 1, 2015 and remainremains 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 rateEEIR revenue collected. As a result, the Company has deferred recognition of energy efficiency implementation rateEEIR revenue collected and has recorded a liability of $10$11 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of September 30, 2014.March 31, 2015.

Joint Dispatch Agreement Application

In May 2014,2013, in anticipation of ON Line's completion, the Company and Sierra Pacific filed its Emission Reduction Capacity Replacement Plan ("ERCR Plan")with the PUCN to combine their power supply resources for joint dispatch purposes and merge the two utilities into a single legal and jurisdictional entity. That filing was withdrawn in compliance with Senate Bill No. 123 ("SB 123") enactedfavor of continued operation of the utilities as separate legal entities, who would conduct joint dispatch of their combined power supply resources utilizing ON Line, governed by the terms of an Interim Joint Dispatch Agreement ("Interim JDA"). In seeking the PUCN's permission to withdraw the May 2013 Nevada Legislature.filing, the Company and Sierra Pacific committed to return to the PUCN with a new application. In March 2015, the Company and Sierra Pacific filed an application with the PUCN seeking approval of an indefinite Joint Dispatch Agreement ("Indefinite JDA"). The filing proposed, among other items, the retirement of Reid Gardner Generating Station units 1, 2 and 3 in 2014 and unit 4 in 2017; the elimination of the Company's ownership interest in Navajo Generating Station in 2019; and a planIndefinite JDA is intended to replace the generating capacity being retired, as requiredcurrently effective Interim JDA, which terminates on December 31, 2015. Joint dispatch transactions addressed by SB 123.the proposed Indefinite JDA include real-time, hourly and daily transactions. The ERCR Plan includes the issuance of requests for proposals for 300 MW of renewable energy to be issuedIndefinite JDA also explicitly governs joint dispatch transactions between 2014 and 2016; the acquisition of a 274-MW natural gas co-generating facility in 2014; the acquisition of a 222-MW natural gas peaking facility in 2014; the construction of a 15-MW solar photovoltaic facility expected to be placed in-service in 2015; and the construction of a 200-MW solar photovoltaic facility expected to be placed in-service in 2016. In the second quarter of 2014, the Company executed various contractual agreements to fulfill the proposed ERCR Plan, which are subject to PUCN approval. The impacts of the ERCR Plan to the Company's 2014 forecasted capital expenditures are included in the Future Uses of Cash previously discussed. The PUCN issued an order dated October 28, 2014 removing the 200-MW solar photovoltaic facility proposed by the Company from the ERCR Plan but accepting the remaining requests. Under Nevada law, the Company may elect to accept the plan as modified by the PUCN, file a motion for reconsideration or withdraw the filing from consideration and file a new ERCR Plan.  In November 2014, Nevada Power filed a request to extend the deadline to make its election.  The Company cannot determine the outcome of this proceeding at this time.


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

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 stateSierra Pacific 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 2015. 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 byutilizing the California ISO.ISO's EIM.

The filingprimary differences between the Interim JDA and the Indefinite JDA relate to EIM transactions with the California ISO. The Indefinite JDA establishes the Company as the EIM scheduling coordinator for both the Company and Sierra Pacific and recognizes that the joint dispatch costs and benefits associated with EIM transactions will be governed by the accounting protocols and allocations set forth in the Indefinite JDA, which are unchanged from those currently in effect under the Interim JDA. The Company and Sierra Pacific requested the PUCN to determine thatact on this application by July 2015, in time to file the amended energy supply plan balancesIndefinite JDA with the objectives of minimizing the cost of supplyFERC 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. The PUCN issued an order in August 2014 finding that it is in the public interest to grant the application and that NV Energy met the merger stipulation requirement to obtain PUCNFERC approval prior to participatingthe "go live" date for EIM transactions, which is October 1, 2015. The Indefinite JDA will continue in an EIM. In April 2014, the California ISO filed the Implementation Agreement entered intoeffect until terminated by the Company and the California ISO. The Implementation Agreement provides the mechanism by which the Company will compensate the California ISO for its sharemutual consent of the costs to upgrade systems, software licenses and other configuration activities. The Implementation Agreement was approved by the FERC in June 2014.parties.

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 is investigating and respondingcompleted 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 archingarcing fires continue to decrease in Nevada and at this time there is no statewide fire problem related to the replacement of electric meters. Management cannot assess or predictIn December 2014, the outcome of these inquires atCompany filed the requested information with the PUCN. In March 2015, the PUCN staff made additional requests and in May 2015, the Company will provide the follow up items. Analysis and internal investigation is continuing, but the Company does not believe this time.will have a material adverse impact on the Consolidated Financial Statements.


18


Environmental Laws and Regulations

The Company is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards,RPS, 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 forecastedforecast 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, 2013.2014.

19

Senate Bill 123 Compliance

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

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

Clean Air Act Regulations

National Ambient Air Quality Standards

The Clean Air Act isSierra Club filed a federal law administeredlawsuit 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 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 policiesintends to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirementspromulgate final sulfur dioxide area designations no later than those implemented by the EPA.July 2, 2016.

Mercury and Air Toxics Standards

The Clean Air Mercury Rule ("CAMR"), issued by the EPANumerous lawsuits have been filed 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,challenging 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.MATS. In April 2014, the D.C. Circuit upheld the MATS requirements.

Regional Haze

The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas"). Some of the Company's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to best available retrofit technology ("BART") requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

Environmental groups have challenged both of the EPA's final determinations with respect to Nevada's regional haze SIP. In May 2012, WildEarth Guardians petitioned the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") to review the EPA's March 2012 approval of Nevada's SIP for all affected units and emissions except nitrogen oxides controls at the Reid Gardner Generating Station. Both the Company and Sierra Pacific intervened in the lawsuit and briefing was completed in February 2013. The matter was heard before the Ninth Circuit in May 2014. On July 17,November 2014, the Ninth Circuit issued its decision, dismissing the petition in part because WildEarth Guardians did not have standing to challenge a portion of the SIP, and denying the petition in part based on its conclusion that the EPA's approval of the Nevada SIP was appropriate.

The Navajo Generating Station, in which the Company is a joint owner with an 11.3% ownership share, is also a source that is subject to the regional haze BART requirements. In January 2013, the EPA announced a proposed federal implementation plan addressing BART and an alternative for the Navajo Generating Station that includes a flexible timeline for reducing nitrogen oxides emissions. The Company, along with the other owners of the facility, have been reviewing the EPA's proposal to determine its impact on the viability of the facility's future operations. The land lease for the Navajo Generating Station is subject to renewal in 2019. Renewal of the lease will require completion of an Environmental Impact Statement as well as a renewal of the fuel supply agreement. In September 2013, the EPA issued a supplemental proposal that included another BART alternative called the Technical Work Group Alternative, which is based on a proposal submitted to the EPA by a group of Navajo Generating Station stakeholders. The EPA accepted comments on the various alternatives through January 6, 2014 and, in July 2014, the EPA announced it had approved the final plan for the Navajo Generating Station, including the reduction of emissions of nitrogen oxides by

20


approximately 80% through the retirement of one unit in 2019 and installation of selective catalytic reduction controls at the other two units by 2030. In October 2014, several groups filed an appeal of the EPA's decision in the Ninth Circuit. Until such time as additional action is taken by the Ninth Circuit and the uncertainties regarding lease and agreement renewal terms for the Navajo Generating Station are addressed, the Company cannot predict the outcome of this matter. The Company filed the ERCR Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019; the PUCN has issued an order and management is assessing its impacts.

Until the EPA takes final action in Nevada on the Navajo Generating Station and the decision is made on the appeal, the Company cannot fully determine the impacts of the Regional Haze regulation on its generating facilities.

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 December 1, 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 thatagreed to hear the MATS appeal on the limited issue of whether the EPA permissibly relied on a cost-benefit analysisunreasonably refused to consider costs in settingdetermining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. Oral argument in 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 ofcase was held before the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remandedin March 2015, and a decision is expected by the case backend of June 2015. The outcome of the United States Supreme Court's decision is uncertain and until the court renders its decision or otherwise implements a stay of the MATS requirements, the Company is proceeding to fulfill its legal obligations to comply with the Second Circuit to conduct further proceedings consistent with its opinion.MATS.


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Coal Combustion Byproduct Disposal

In June 2013,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 proposed effluent limitation guidelinesin the Federal Register on April 17, 2015 and will be effective on October 14, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the steam electric power generating sector. These guidelines, which had not been revised since 1982, were revised in responsedisposal 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 EPA's concernsmore stringent regulatory requirements.

As defined by the final rule, the Company operates ten evaporative surface impoundments that are likely to fall within the additiondefinition of controls for air emissions have changed the effluent discharged from coal-final rule and natural gas-fueled generating facilities. Whileone landfill that contains coal combustion byproducts. The Company is assessing the EPA expectedrequirements of 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.


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In April 2014, the EPAdetermine required compliance activities 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 November 14, 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.associated costs.

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 in the event ofif credit exposures on a credit rating downgradenet basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2014,March 31, 2015, the applicable credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of September 30, 2014,March 31, 2015, the Company would have been required to post $57$75 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of the Company's collateral requirements specific to the Company's derivative contracts.

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K10‑K for the year ended December 31, 2013.2014. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2013.2014.


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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, 2013.2014. The Company's exposure to market risk and its management of such risk has not changed materially since December 31, 2013.2014. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 1 of this Form 10‑Q for disclosure of the Company's derivative positions as of September 30, 2014.March 31, 2015.


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Item 4.    Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon that evaluation, the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that the Company's disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to management, including the Company's President (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company's internal control over financial reporting during the quarter ended September 30, 2014March 31, 2015 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.


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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, 2013.2014.

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.


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SIGNATURES


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

  NEVADA POWER COMPANY
  (Registrant)
   
   
   
Date:November 7, 2014May 1, 2015/s/ E. Kevin Bethel
  E. Kevin Bethel
  Senior Vice President, and Chief Financial Officer and Director
  (principal financial and accounting officer)



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EXHIBIT INDEX

Exhibit No.Description

10.1$400,000,000 Amended and Restated Credit Agreement, dated as of June 27, 2014, among Nevada 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 Nevada Power Company Current Report on Form 8-K dated June 27, 2014).
15Awareness Letter of Independent Registered Public Accounting Firm.
31.1Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101
The following financial information from Nevada Power Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014March 31, 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.








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