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 March 31, 2014

(Mark One)


or

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

For the transition period from _____ to _____

þ

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED   March 31, 2013

OR

¨

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

Registrant, Address of

I.R.S. Employer

Principal Executive Offices

Identification

State of

Commission File Number

and Telephone Number

Exact name of registrant as specified in its charter; State or other jurisdiction of incorporation or organization

Number

Incorporation

IRS Employer Identification No.

000-52378

NEVADA POWER COMPANY

88-0420104

1-08788

NV ENERGY, INC.

(A Nevada Corporation)

88-0198358

Nevada

6226 West Sahara Avenue

Las Vegas, Nevada 89146

(702) 402-5000

702-402-5000

2-28348

NEVADA POWER COMPANY d/b/a

Securities registered pursuant to Section 12(b) of the Act: None

88-0420104

Nevada

NV ENERGY

Securities registered pursuant to Section 12(g) of the Act:

6226 West Sahara Avenue

Common Stock, $1.00 stated value

Las Vegas, Nevada 89146

(702) 402-5000

0-00508

SIERRA PACIFIC POWER COMPANY d/b/a

88-0044418

Nevada

NV ENERGY

P.O. Box 10100

(6100 Neil Road)

Reno, Nevada 89520-0400 (89511)

(775) 834-4011


Indicate by check mark whether 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  þ T Noo  (Response applicable to all registrants)


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website,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  þ T Noo    (Response applicable to all registrants)


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

NV Energy, Inc.:

Large accelerated filer þo

Accelerated filero

Non-accelerated filer ox

Smaller reporting company  o 

Nevada Power Company:

Large accelerated filero

Accelerated filer o

Non-accelerated filer þ

  Smaller reporting company     o 

Sierra Pacific Power Company:

Large accelerated filer o

Accelerated filer o

Non-accelerated filer þ

  Smaller reporting company     o 


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

Indicate the number


All shares of shares outstanding common stock of each of the issuer’s classes of Common Stock, as of the latest practicable date.

Class

Outstanding at May 7, 2013

Common Stock, $1.00 par value

of NV Energy, Inc.

235,447,475 Shares

Nevada Power Company are held by its parent company, NV Energy, Inc., which is the sole holderan indirect, wholly owned subsidiary of theBerkshire Hathaway Energy Company, formerly known as MidAmerican Energy Holdings Company. As of April 30, 2014, 1,000 shares of outstanding Common Stock,common stock, $1.00 stated value, of Nevada Power Company.

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 stated value, of Sierra Pacific Power Company.

This combined Quarterly Report on Form 10-Q is separately filed by NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company.  Information contained in this document relating to Nevada Power Company is filed by NV Energy, Inc. and separately by Nevada Power Company on its own behalf.  Nevada Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Nevada Power Company.  Information contained in this document relating to Sierra Pacific Power Company is filed by NV Energy, Inc. and separately by Sierra Pacific Power Company on its own behalf.  Sierra Pacific Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Sierra Pacific Power Company.

were outstanding.







TABLE OF CONTENTS

NV ENERGY, INC.

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2013

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

Acronyms & Terms

3

PART I

ITEM 1.   

Financial Statements

NV Energy, Inc.

5

Consolidated Balance Sheets – March 31, 2013 and December 31, 2012

6

Consolidated Statements of Cash Flows -  Three Months Ended March 31, 2013 and 2012

8

Consolidated Statements of Shareholders’ Equity - Three Months Ended March 31, 2013 and 2012

9

Nevada Power Company

Consolidated Statements of Comprehensive Income (Loss) – Three  Months Ended March 31, 2013 and 2012

10

Consolidated Balance Sheets – March 31, 2013 and December 31, 2012

11

Consolidated Statements of Cash Flows -  Three Months Ended March 31, 2013  and 2012

13

Consolidated Statements of Shareholder’s Equity - Three Months Ended March 31, 2013 and 2012

14

Sierra Pacific Power Company

Consolidated Statements of Comprehensive Income   – Three Months Ended March 31, 2013 and 2012

15

Consolidated Balance Sheets – March 31, 2013 and December 31, 2012

16

Consolidated Statements of Cash Flows - Three Months Ended March 31, 2013 and 2012

18

Consolidated Statements of Shareholder’s Equity - Three Months Ended March 31, 2013 and 2012

19

Condensed Notes to Financial Statements

Note 1.     Summary of Significant Accounting Policies

20

Note 2.     Segment Information

21

Note 3.     Regulatory Actions

22

Note 4.     Long-Term Debt

24

Note 5.     Fair Value of Financial Instruments

24

Note 6.     Retirement Plan and Post-Retirement Benefits

25

Note 7.     Commitments and Contingencies

26

Note 8.     Earnings per Share (NVE)

29

Note 9. Common Stock and Other Paid-In Capital

29

ITEM 2.   

Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations

31

35

Nevada Power Company

39

Sierra Pacific Power Company

46

ITEM 3.   

Quantitative and Qualitative Disclosures aboutAbout Market Risk

53

ITEM 4.   

54

PART II – OTHER INFORMATION

ITEM

55

ITEM

55

ITEM

55

ITEM

55

ITEM

55

ITEM

55

ITEM

56




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 Certifications

57

Related Entities
   
CompanyNevada Power Company and its subsidiaries
Berkshire Hathaway EnergyBerkshire Hathaway Energy Company (formerly MidAmerican Energy Holdings Company)
NV EnergyNV Energy, Inc.
Sierra PacificSierra Pacific Power Company, an electric and natural gas utility wholly owned by NV Energy
Higgins Generating Station530-megawatt generating facility in Nevada
Lenzie Generating Station1,102-megawatt generating facility in Nevada
Navajo Generating Station2,250-megawatt generating facility in Arizona
ON Line500-kilovolt transmission line connecting the Company and Sierra Pacific
Reid Gardner Generating Station557-megawatt generating facility in Nevada
  

2


ACRONYMS AND TERMS

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

Certain Industry Terms

Acronym/Term

Meaning

AFUDC

2012 Form 10-K

NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2012

AFUDC-debt

Allowance for Borrowed Funds Used During Construction

AFUDC-equity

EPA

Allowance for Equity Funds Used During Construction

ARO

Asset Retirement Obligation

BOD

Board of Directors

BTER

Base Tariff Energy Rate

BTGR

Base Tariff General Rate

CA ISO

California Independent System Operator Corporation

California Assets

SPPC's California electric distribution and generation assets

CalPeco

California Pacific Electric Company

CDD

Cooling degree days

CDWR

California Department of Water Resources

CIAC

Contributions in Aid of Construction

CWIP

Construction Work-in-Progress

dba

Doing business as

DEAA

Deferred Energy Accounting Adjustment

Dth

Decatherm

EEIR

Energy Efficiency Implementation Rate

EEPR

Energy Efficiency Program Rate

EPA

United States Environmental Protection Agency

EPS

FERC

Earnings per Share

FASB

Financial Accounting Standards Board

FASC

FASB Accounting Standards Codification

FERC

Federal Energy Regulatory Commission

Fitch

GWh

Fitch Ratings, Ltd.

Gigawatt Hours

Ft. Churchill Generating Station

MW

226 megawatt nominally rated Fort Churchill Generating Station

Megawatts

GAAP

MWh

Generally Accepted Accounting Principles in the United States

Megawatt Hours

GBT

PUCN

Great Basin Transmission, LLC, a wholly owned subsidiary of Texas Nevada Transmission, LLC

GBT-South

Great Basin Transmission South, LLC, a wholly owned subsidiary of GBT

GRC

General Rate Case

Harry Allen Generating Station

642 megawatt nominally rated Harry Allen Generating Station

HDD

Heating degree days

Higgins Generating Station

598 megawatt nominally rated Walter M. Higgins, III Generating Station

kV

Kilovolt

Lenzie Generating Station

1,102 megawatt nominally rated Chuck Lenzie Generating Station

Mohave Generating Station

1,580 megawatt nominally rated Mohave Generating Station

Moody’s

Moody’s Investors Services, Inc.

MW

Megawatt

MWh

Megawatt hour

Navajo Generating Station

255 megawatt nominally rated Navajo Generating Station

NEICO

Nevada Electric Investment Company

NERC

North American Electric Reliability Corporation

Ninth Circuit

United States Court of Appeals for the Ninth Circuit

NOL

Net Operating Loss

NPC

Nevada Power Company d/b/a NV Energy

NPC Credit Agreement

$500 million Revolving Credit Facility entered into in March 2012 between NPC and Wells Fargo Bank,

N.A., as administrative agent for the lenders a party thereto

NPC Indenture

NPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and the Bank

of New York Mellon Trust Company, N.A., as Trustee

NRSRO

Nationally Recognized Statistical Rating Organization

NVE

NV Energy, Inc.

NV Energize

A smart grid infrastructure that is expected to enable the widespread use of Smart Meters that will provide

customers the ability to more directly manage their energy usage

ON Line

250 mile 500 kV transmission line connecting NVE’s northern and southern service territories

Portfolio Standard

Nevada Renewable Energy Portfolio Standard

PUCN

Public Utilities Commission of Nevada

Reid Gardner Generating Station

325 megawatt nominally rated Reid Gardner Generating Station

REPR

Renewable Energy Program Rate

ROR

Rate of Return

S&P

Standard & Poor’s

3



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 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;
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 facilities;
changes in the Company's credit ratings;
the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;
the impact of inflation on costs and the Company's ability to recover such costs in rates;
increases in employee healthcare costs, including the implementation of the Affordable Care Act;
the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements related to the Company's participation in NV Energy's benefit plans;
unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generating facilities and infrastructure additions;

iii



the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company's consolidated financial results; and
other business or investment considerations that may be disclosed from time to time in the Company's filings with the United States Securities and Exchange Commission or in other publicly disseminated written documents.

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


iv



PART I

Salt River

Salt River Project

SEC

United States Securities and Exchange Commission

Silverhawk Generating Station

395 megawatt nominally rated Silverhawk Generating Station

Smart Meters

Advanced service delivery meters installed as part of the NV Energize project

SNWA

Southern Nevada Water Authority

SPPC

Sierra Pacific Power Company d/b/a NV Energy

SPPC Credit Agreement

$250 million Revolving Credit Facility entered into in March 2012 between SPPC and Wells Fargo

Bank, N.A., as administrative agent for the lenders a party thereto

SPPC Indenture

SPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and

the Bank of New York Mellon Trust Company, N.A., as Trustee

STPR

Solar Thermal Program Rate

Term Loan

$195 million loan agreement entered into on October 7, 2011 between NVE and JPMorgan Chase Bank,

N.A., as administrative agent for the lenders a party thereto

TMWA

Truckee Meadows Water Authority

Tracy Generating Station

541 megawatt nominally rated Frank A. Tracy Generating Station

TRED

Temporary Renewable Energy Development

TUA

Transmission Use and Capacity Exchange Agreement with GBT-South

U.S.

United States of America

Utilities

Nevada Power Company and Sierra Pacific Power Company

Valmy Generating Station

261 megawatt nominally rated Valmy Generating Station

VIE

Variable Interest Entity

WSPP

Western Systems Power Pool

Item 1.    Financial Statements

4



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 March 31, 2014, and the related consolidated statements of operations, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2014 and 2013. These interim financial statements are the responsibility of the Company's management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Nevada Power Company and subsidiaries as of December 31, 2013, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated March 31, 2014, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2013 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.


/s/ Deloitte & Touche LLP


Las Vegas, Nevada
ITEM 1.May 2, 2014                FINANCIAL STATEMENTS


1

NV ENERGY, INC.



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

 As of
 March 31, December 31,
 2014 2013
ASSETS
    
Current assets:   
Cash and cash equivalents$99
 $126
Accounts receivable, net231
 227
Inventories70
 73
Regulatory assets64
 81
Deferred income taxes135
 152
Other current assets50
 39
Total current assets649
 698
    
Property, plant and equipment, net6,984
 6,992
Regulatory assets1,033
 1,057
Other assets88
 88
    
Total assets$8,754
 $8,835
    
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:   
Accounts payable$202
 $240
Accrued interest42
 61
Accrued property, income and other taxes25
 29
Accrued employee expenses9
 6
Regulatory liabilities68
 74
Current portion of long-term debt260
 22
Customer deposits and other80
 74
Total current liabilities686
 506
    
Long-term debt3,307
 3,555
Regulatory liabilities317
 312
Deferred income taxes1,285
 1,298
Other long-term liabilities262
 274
Total liabilities5,857
 5,945
    
Commitments and contingencies (Note 8)
 
    
Shareholder's equity:   
Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding
 
Other paid-in capital2,308
 2,308
Retained earnings592
 586
Accumulated other comprehensive loss, net(3) (4)
Total shareholder's equity2,897
 2,890
    
Total liabilities and shareholder's equity$8,754
 $8,835
    
The accompanying notes are an integral part of the consolidated financial statements.




2



NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

OPERATIONS (Unaudited)

(DollarsAmounts in Thousands, Except Share Amounts)

(Unaudited)

millions)

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

 

 

 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

OPERATING REVENUES

$

584,222 

 

$

611,420 

 

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

 

Fuel for power generation

 

147,248 

 

 

117,035 

 

 

 

Purchased power

 

121,310 

 

 

117,116 

 

 

 

Gas purchased for resale

 

37,620 

 

 

31,617 

 

 

 

Deferred energy

 

(79,065)

 

 

(11,739)

 

 

 

Energy efficiency program costs

 

9,845 

 

 

19,425 

 

 

 

Other operating expenses

 

104,672 

 

 

103,601 

 

 

 

Maintenance

 

24,906 

 

 

32,526 

 

 

 

Depreciation and amortization

 

96,002 

 

 

90,862 

 

 

 

Taxes other than income

 

16,476 

 

 

14,509 

 

 

Total Operating Expenses

 

479,014 

 

 

514,952 

 

 

OPERATING INCOME

 

105,208 

 

 

96,468 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

Interest expense

 

 

 

 

 

 

 

 

(net of AFUDC-debt: $2,131 and $1,595)

 

(73,337)

 

 

(77,931)

 

 

 

Interest expense on regulatory items

 

(827)

 

 

(2,202)

 

 

 

AFUDC-equity

 

2,889 

 

 

1,932 

 

 

 

Other income

 

3,820 

 

 

4,194 

 

 

 

Other expense

 

(4,251)

 

 

(3,060)

 

 

Total Other Income (Expense)

 

(71,706)

 

 

(77,067)

 

 

Income Before Income Tax Expense

 

33,502 

 

 

19,401 

 

 

 

 

 

 

 

 

 

 

 

Income tax expense

 

12,027 

 

 

7,228 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

21,475 

 

 

12,173 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

Change in compensation retirement benefits liability and amortization

 

 

 

 

 

 

 

(Net of taxes $(136) and $(89) in 2013 and 2012, respectively)

 

246 

 

 

155 

 

 

Change in market value of risk management assets and liabilities

 

 

 

 

 

 

 

(Net of taxes $(110) and $141 in 2013 and 2012, respectively)

 

199 

 

 

(246)

 

 

 

 

 

 

 

 

 

 

OTHER COMPREHENSIVE INCOME (LOSS)

 

445 

 

 

(91)

 

 

 

 

 

 

 

 

 

 

 

COMPREHENSIVE INCOME

$

21,920 

 

$

12,082 

 

 

 

 

 

 

 

 

 

 

 

Amount per share basic and diluted (Note 8)

 

 

 

 

 

 

 

 

Net income per share - basic and diluted

$

0.09 

 

$

0.05 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Shares of Common Stock Outstanding - basic

235,193,702 

 

235,999,750 

 

 

Weighted Average Shares of Common Stock Outstanding - diluted

237,005,888 

 

237,526,863 

 

 

Dividends Declared Per Share of Common Stock

$

0.19 

 

$

0.13 

 

 

 

 

 

 

 

 

 

 

 

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

 


5

 Three-Month Periods
 Ended March 31,
 2014 2013
    
Operating revenue$417
 $370
    
Operating costs and expenses:   
Cost of fuel, energy and capacity203
 142
Operating and maintenance expense82
 99
Depreciation and amortization66
 65
Property and other taxes11
 10
Total operating costs and expenses362
 316
    
Operating income55
 54
    
Other income (expense):   
Interest expense, net of allowance for debt funds(51) (53)
Allowance for equity funds
 2
Other, net6
 5
Total other income (expense)(45) (46)
    
Income before income tax expense10
 8
Income tax expense4
 3
Net income$6
 $5
    
The accompanying notes are an integral part of these consolidated financial statements.


3


NV ENERGY, INC.


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(DollarsAmounts in Thousands, Except Share Amounts)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

 

 

 

 

 

2013 

 

2012 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets: 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 250,953 

 

$

298,271 

 

 

 

Accounts receivable less allowance for uncollectible accounts:

 

 

 

 

 

 

 

 

 

2013 - $6,533; 2012 - $8,748

 

 317,191 

 

 

373,099 

 

 

 

Materials, supplies and fuel, at average cost

 

 133,613 

 

 

138,337 

 

 

 

Deferred income taxes

 

 88,648 

 

 

60,592 

 

 

 

Other current assets

 

 54,397 

 

 

40,750 

 

 

Total Current Assets

 

 844,802 

 

 

911,049 

 

 

 

 

 

 

 

 

 

 

 

 

Utility Property:

 

 

 

 

 

 

 

 

Plant in service

 

 12,077,001 

 

 

12,031,053 

 

 

 

Construction work-in-progress

 

 730,262 

 

 

708,109 

 

 

 

Total

 

 12,807,263 

 

 

12,739,162 

 

 

Less accumulated provision for depreciation

 

 3,378,468 

 

 

3,313,188 

 

 

 

Total Utility Property, Net

 

 9,428,795 

 

 

9,425,974 

 

 

 

 

 

 

 

 

 

 

 

 

Investments and other property, net

 

 58,389 

 

 

56,660 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Charges and Other Assets:

 

 

 

 

 

 

 

 

Deferred energy (Note 3)

 

 84,120 

 

 

87,072 

 

 

 

Regulatory assets

 

 1,102,348 

 

 

1,132,768 

 

 

 

Regulatory asset for pension plans

 

 277,836 

 

 

281,195 

 

 

 

Other deferred charges and assets

 

 82,343 

 

 

89,418 

 

 

Total Deferred Charges and Other Assets

 

 1,546,647 

 

 

1,590,453 

 

 

 

 

 

 

 

 

 

 

 

 

TOTAL ASSETS

$

 11,878,633 

 

$

11,984,136 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Continued)

 

millions, except shares)

6


          Accumulated  
      Other   Other Total
  Common Stock Paid-in Retained Comprehensive Shareholder's
  Shares Amount Capital Earnings Loss, Net Equity
Balance at December 31, 2012 1,000
 $
 $2,308
 $619
 $(5) $2,922
Net income 
 
 
 5
 
 5
Dividends declared 
 
 
 (50) 
 (50)
Balance at March 31, 2013 1,000
 $
 $2,308
 $574
 $(5) $2,877
             
Balance at December 31, 2013 1,000
 $
 $2,308
 $586
 $(4) $2,890
Net income 
 
 
 6
 
 6
Other 
 
 
 
 1
 1
Balance at March 31, 2014 1,000
 $
 $2,308
 $592
 $(3) $2,897
             
The accompanying notes are an integral part of these consolidated financial statements.


4

 

 

 

NV ENERGY, INC.

 

 

 

CONSOLIDATED BALANCE SHEETS

 

 

 

(Dollars in Thousands, Except Share Amounts)

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

 

LIABILITIES AND SHAREHOLDERS' EQUITY

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

 

Current maturities of long-term debt (Note 4)

$

 481,342 

 

$

356,283 

 

 

Accounts payable

 

 280,206 

 

 

332,245 

 

 

Accrued expenses

 

 95,080 

 

 

127,693 

 

 

Deferred energy (Note 3)

 

 56,336 

 

 

136,865 

 

 

Other current liabilities

 

 69,306 

 

 

66,221 

 

Total Current Liabilities

 

 982,270 

 

 

1,019,307 

 

 

 

 

 

 

 

 

 

 

Long-term debt (Note 4)

 

 4,541,241 

 

 

4,669,798 

 

 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

 

Deferred income taxes

 

 1,510,369 

 

 

1,470,973 

 

 

Deferred investment tax credit

 

 12,984 

 

 

13,538 

 

 

Accrued retirement benefits

 

 164,315 

 

 

162,260 

 

 

Regulatory liabilities

 

 558,692 

 

 

550,687 

 

 

Other deferred credits and liabilities

 

 564,911 

 

 

540,202 

 

Total Deferred Credits and Other Liabilities

 

 2,811,271 

 

 

2,737,660 

 

 

 

 

 

 

 

 

Shareholders' Equity:

 

 

 

 

 

 

 

Common stock, $1.00 par value; 350 million shares authorized; 235,999,750 issued

 

 

 

 

 

 

 

 

for 2013 and 2012; 235,526,514 and 235,079,156 outstanding for 2013 and 2012, respectively

 

 236,000 

 

 

236,000 

 

 

Treasury stock at cost, 473,236 shares and 920,594 shares for 2013 and 2012, respectively

 

 (8,660) 

 

 

 (16,804) 

 

 

Other paid-in capital

 

 2,714,107 

 

 

2,712,943 

 

 

Retained earnings

 

 612,030 

 

 

635,303 

 

 

Accumulated other comprehensive loss

 

 (9,626) 

 

 

(10,071)

 

Total Shareholders' Equity

 

 3,543,851 

 

 

3,557,371 

 

 

 

 

 

 

 

 

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY

$

 11,878,633 

 

$

11,984,136 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Concluded)

7




NEVADA POWER COMPANY AND SUBSIDIARIES

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(DollarsAmounts in Thousands)

(Unaudited)

millions)

 

 

 

 

 

 

 

For the Three Months Ended,

 

 

 

 

 

March 31,

 

 

 

 

 

2013 

 

2012 

 

 

CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

Net Income

$

 21,475 

 

$

 12,173 

 

 

 

Adjustments to reconcile net income to net cash from operating activities:

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 96,002 

 

 

 90,862 

 

 

 

 

Deferred taxes and deferred investment tax credit

 

 11,956 

 

 

 (5,183) 

 

 

 

 

AFUDC-equity

 

 (2,889) 

 

 

 (1,932) 

 

 

 

 

Deferred energy

 

 (77,578) 

 

 

 (9,134) 

 

 

 

 

Amortization of other regulatory assets

 

 41,621 

 

 

 39,028 

 

 

 

 

Deferred rate increase

 

 2,103 

 

 

 2,691 

 

 

 

 

Other, net

 

 (897) 

 

 

 1,575 

 

 

 

Changes in certain assets and liabilities:

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 68,131 

 

 

 31,208 

 

 

 

 

Materials, supplies and fuel

 

 4,815 

 

 

 (874) 

 

 

 

 

Other current assets

 

 (13,648) 

 

 

 (13,021) 

 

 

 

 

Accounts payable

 

 (29,795) 

 

 

 (37,825) 

 

 

 

 

Accrued retirement benefits

 

 2,055 

 

 

 2,221 

 

 

 

 

Other current liabilities

 

 (29,335) 

 

 

 (29,348) 

 

 

 

 

Other deferred assets

 

 (1,263) 

 

 

 (1,602) 

 

 

 

 

Other regulatory assets

 

 (2,379) 

 

 

 4,164 

 

 

 

 

Other deferred liabilities

 

 (1,480) 

 

 

 (17,687) 

 

 

Net Cash from Operating Activities

 

 88,894 

 

 

 67,316 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

 

Additions to utility plant (excluding AFUDC-equity)

 

 (97,948) 

 

 

 (115,817) 

 

 

 

 

Customer advances for construction

 

 (629) 

 

 

 (184) 

 

 

 

 

Contributions in aid of construction

 

 13,570 

 

 

 26,052 

 

 

 

 

Investments and other property - net

 

 111 

 

 

 48 

 

 

Net Cash used by Investing Activities

 

 (84,896) 

 

 

 (89,901) 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

 

Proceeds from issuance of long-term debt, net of costs

 

 - 

 

 

 10,951 

 

 

 

 

Retirement of long-term debt

 

 (3,671) 

 

 

 (3,295) 

 

 

 

 

Sale of common stock

 

 754 

 

 

 - 

 

 

 

 

Common stock repurchased

 

 (3,651) 

 

 

 - 

 

 

 

 

Dividends paid

 

 (44,748) 

 

 

 (30,680) 

 

 

Net Cash used by Financing Activities

 

 (51,316) 

 

 

 (23,024) 

 

 

 

 

 

 

 

 

 

 

 

 

Net Decrease in Cash and Cash Equivalents

 

 (47,318) 

 

 

 (45,609) 

 

 

Beginning Balance in Cash and Cash Equivalents

 

 298,271 

 

 

 145,944 

 

 

Ending Balance in Cash and Cash Equivalents

$

 250,953 

 

$

 100,335 

 

 

 

 

 

 

 

 

 

 

 

 

Supplemental Disclosures of Cash Flow Information:

 

 

 

 

 

 

 

 

Cash paid during period for:

 

 

 

 

 

 

 

 

 

Interest

$

 88,337 

 

$

 88,606 

 

 

 

 

Income taxes

$

 2 

 

$

 - 

 

 

 

Significant non-cash transactions:

 

 

 

 

 

 

 

 

 

Accrued construction expenses as of March 31,

$

 61,262 

 

$

 85,850 

 

 

 

 

Issuance of treasury stock

$

 11,041 

 

$

 - 

 

 

 

 

 

 

 

 

 

 

 

 

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

 


8

 Three-Month Periods
 Ended March 31,
 2014 2013
    
Cash flows from operating activities:   
Net income$6
 $5
Adjustments to reconcile net income to net cash flows from operating activities:   
Depreciation and amortization66
 65
Deferred income taxes and amortization of investment tax credits4
 3
Allowance for equity funds
 (2)
Amortization of deferred energy13
 (27)
Deferred energy(2) (17)
Amortization of other regulatory assets12
 22
Other, net5
 1
Changes in other operating assets and liabilities:   
Accounts receivable and other assets(32) 40
Inventories3
 (3)
Accounts payable and other liabilities(42) (50)
Net cash flows from operating activities33
 37
    
Cash flows from investing activities:   
Capital expenditures(58) (59)
Contributions in aid of construction and customer advances9
 6
Net cash flows from investing activities(49) (53)
    
Cash flows from financing activities:   
Repayments of long-term debt(11) (3)
Dividends paid
 (50)
Net cash flows from financing activities(11) (53)
    
Net change in cash and cash equivalents(27) (69)
Cash and cash equivalents at beginning of period126
 201
Cash and cash equivalents at end of period$99
 $132
    
The accompanying notes are an integral part of these consolidated financial statements.

5

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

Common

 

Common

 

 

Treasury

 

 

Treasury

 

Other

 

 

 

 

 Other 

 

Total

 

 

 

 

 Stock  

 

 Stock 

 

 

Stock

 

 

Stock

 

Paid-in

 

Retained

 

 Comprehensive 

 

 Shareholders' 

 

 

 

 

Shares

 

 Amount 

 

 

Shares

 

 

Amount

 

Capital

 

Earnings

 

 Income (Loss)

 

 Equity 

December 31, 2011

235,999,750 

 

$

 236,000 

 

 

 - 

 

$

 - 

 

$

 2,713,736 

 

$

 464,277 

 

$

 (7,934) 

 

$

 3,406,079 

 

Net Income

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 12,173 

 

 

 - 

 

 

 12,173 

 

Change in compensation retirement benefits

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

liability and amortization (net of taxes $(89))

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 155 

 

 

 155 

 

Change in market value of risk management

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

assets and liabilities (net of taxes $ 141)

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 (246) 

 

 

 (246) 

 

Dividends Declared

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 (30,680) 

 

 

 - 

 

 

 (30,680) 

March 31, 2012

235,999,750 

 

$

236,000 

 

 

 

$

 

$

2,713,736 

 

$

445,770 

 

$

(8,025)

 

$

3,387,481 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 235,999,750 

 

$

 236,000 

 

 

 (920,594) 

 

$

 (16,804) 

 

$

 2,712,943 

 

$

 635,303 

��

$

 (10,071) 

 

$

 3,557,371 

 

Net Income

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 21,475 

 

 

 - 

 

 

 21,475 

 

Employee Benefits

 - 

 

 

 - 

 

 

 644,536 

 

 

 11,795 

 

 

 1,164 

 

 

 - 

 

 

 - 

 

 

 12,959 

 

Change in compensation retirement benefits

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

liability and amortization (net of taxes $(136))

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 246 

 

 

 246 

 

Change in market value of risk management

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

assets and liabilities (net of taxes $(110))

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 199 

 

 

 199 

 

Common stock repurchased

 - 

 

 

 - 

 

 

 (197,178) 

 

 

 (3,651) 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 (3,651) 

 

Dividends Declared

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 (44,748) 

 

 

 - 

 

 

 (44,748) 

March 31, 2013

235,999,750 

 

$

236,000 

 

 

(473,236)

 

$

(8,660)

 

$

2,714,107 

 

$

612,030 

 

$

(9,626)

 

$

3,543,851 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

9




NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

 

 

 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

OPERATING REVENUES

$

 371,863 

 

$

395,688 

 

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

 

Fuel for power generation

 

 105,531 

 

 

80,549 

 

 

 

Purchased power

 

 81,408 

 

 

81,531 

 

 

 

Deferred energy

 

 (45,355) 

 

 

2,171 

 

 

 

Energy efficiency program costs

 

 7,967 

 

 

15,774 

 

 

 

Other operating expenses

 

 67,392 

 

 

66,462 

 

 

 

Maintenance

 

 18,075 

 

 

23,073 

 

 

 

Depreciation and amortization

 

 68,661 

 

 

64,990 

 

 

 

Taxes other than income

 

 9,959 

 

 

8,454 

 

 

Total Operating Expenses

 

 313,638 

 

 

343,004 

 

 

OPERATING INCOME

 

 58,225 

 

 

52,684 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

Interest expense

 

 

 

 

 

 

 

 

(net of AFUDC-debt: $1,837 and $1,179)

 

 (51,259) 

 

 

(54,405)

 

 

 

Interest income (expense) on regulatory items

 

 (802) 

 

 

(2,016)

 

 

 

AFUDC-equity

 

 2,366 

 

 

1,413 

 

 

 

Other income

 

 2,404 

 

 

1,709 

 

 

 

Other expense

 

 (2,401) 

 

 

(1,346)

 

 

Total Other Income (Expense)

 

 (49,692) 

 

 

(54,645)

 

 

Income (Loss) Before Income Tax Expense

 

 8,533 

 

 

(1,961)

 

 

 

 

 

 

 

 

 

 

 

Income tax expense

 

 3,088 

 

 

(645)

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS)

 

 5,445 

 

 

(1,316)

 

 

 

 

 

 

 

 

 

 

Other comprehensive income:

 

 

 

 

 

 

 

Change in compensation retirement benefits liability and amortization

 

 

 

 

 

 

 

(Net of taxes $(54) and $(32) in 2013 and 2012, respectively)

 

 97 

 

 

63 

 

 

 

 

 

 

 

 

 

 

 

COMPREHENSIVE INCOME (LOSS)

$

 5,542 

 

$

(1,253)

 

 

 

 

 

 

 

 

 

 

 

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

 

10


NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

 

 

 

 

 

2013 

 

2012 

 

 

ASSETS

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets: 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 132,216 

 

$

201,202 

 

 

 

Accounts receivable less allowance for uncollectible accounts:

 

 

 

 

 

 

 

 

 

2013 - $5,580; 2012 - $7,622

 

 198,740 

 

 

248,501 

 

 

 

Materials, supplies and fuel, at average cost

 

 80,998 

 

 

77,675 

 

 

 

Deferred income taxes

 

 80,265 

 

 

48,590 

 

 

 

Other current assets

 

 38,008 

 

 

28,763 

 

 

Total Current Assets

 

 530,227 

 

 

604,731 

 

 

 

 

 

 

 

 

 

 

 

 

Utility Property:

 

 

 

 

 

 

 

 

Plant in service

 

 8,399,239 

 

 

8,363,566 

 

 

 

Construction work-in-progress

 

 603,495 

 

 

567,941 

 

 

 

 

Total

 

 9,002,734 

 

 

8,931,507 

 

 

 

Less accumulated provision for depreciation

 

 2,091,598 

 

 

2,035,322 

 

 

 

 

Total Utility Property, Net

 

 6,911,136 

 

 

6,896,185 

 

 

 

 

 

 

 

 

 

 

 

 

Investments and other property, net

 

 51,201 

 

 

49,808 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Charges and Other Assets:

 

 

 

 

 

 

 

 

Deferred energy (Note 3)

 

 84,120 

 

 

87,072 

 

 

 

Regulatory assets

 

 781,916 

 

 

804,013 

 

 

 

Regulatory asset for pension plans

 

 135,191 

 

 

136,682 

 

 

 

Other deferred charges and assets

 

 64,924 

 

 

62,654 

 

 

Total Deferred Charges and Other Assets

 

 1,066,151 

 

 

1,090,421 

 

 

 

 

 

 

 

 

 

 

 

 

TOTAL ASSETS

$

 8,558,715 

 

$

8,641,145 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Continued)

 

AND SUBSIDIARIES

11


 

 

 

NEVADA POWER COMPANY

 

 

 

 

CONSOLIDATED BALANCE SHEETS

 

 

 

 

(Dollars in Thousands, Except Share Amounts)

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

 

 

 

 

 

2013 

 

2012 

 

 

LIABILITIES AND SHAREHOLDER'S EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

 

 

Current maturities of long-term debt (Note 4)

$

 231,075 

 

$

106,048 

 

 

 

Accounts payable

 

 168,582 

 

 

201,193 

 

 

 

Accounts payable, affiliated companies

 

 39,650 

 

 

42,036 

 

 

 

Accrued expenses

 

 58,774 

 

 

86,433 

 

 

 

Deferred energy (Note 3)

 

 38,915 

 

 

86,102 

 

 

 

Other current liabilities

 

 54,935 

 

 

52,567 

 

 

Total Current Liabilities

 

 591,931 

 

 

574,379 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt (Note 4)

 

 3,102,390 

 

 

3,230,808 

 

 

 

 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

 

 

Deferred income taxes

 

 1,136,115 

 

 

1,101,804 

 

 

 

Deferred investment tax credit

 

 4,407 

 

 

4,688 

 

 

 

Accrued retirement benefits

 

 50,328 

 

 

49,381 

 

 

 

Regulatory liabilities

 

 329,806 

 

 

323,400 

 

 

 

Other deferred credits and liabilities

 

 465,878 

 

 

434,367 

 

 

Total Deferred Credits and Other Liabilities

 

 1,986,534 

 

 

1,913,640 

 

 

 

 

 

 

 

 

 

 

Shareholder's Equity:

 

 

 

 

 

 

 

 

Common stock, $1.00 par value; 1,000 shares authorized

 

 

 

 

 

 

 

 

 

issued and outstanding for 2013 and 2012

 

 1 

 

 

 

 

 

Other paid-in capital

 

 2,308,211 

 

 

2,308,211 

 

 

 

Retained earnings

 

 574,057 

 

 

618,612 

 

 

 

Accumulated other comprehensive loss

 

 (4,409) 

 

 

(4,506)

 

 

Total Shareholder's Equity

 

 2,877,860 

 

 

2,922,318 

 

 

 

 

 

 

 

 

 

 

 

 

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY

$

 8,558,715 

 

$

8,641,145 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Concluded)

 

12


NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

 

 

 

 

For the Three Months Ended,

 

 

 

 

 

March 31,

 

 

 

 

 

2013 

 

2012 

 

 

CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net Income (Loss)

$

 5,445 

 

$

(1,316)

 

 

 

Adjustments to reconcile net income to net cash from operating activities:

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 68,661 

 

 

64,990 

 

 

 

 

Deferred taxes and deferred investment tax credit

 

 2,949 

 

 

(6,349)

 

 

 

 

AFUDC-equity

 

 (2,366) 

 

 

(1,413)

 

 

 

 

Deferred energy

 

 (44,235) 

 

 

4,050 

 

 

 

 

Amortization of other regulatory assets

 

 22,119 

 

 

18,301 

 

 

 

 

Deferred rate increase

 

 2,103 

 

 

2,691 

 

 

 

 

Other, net

 

 (4,261) 

 

 

(796)

 

 

 

  Changes in certain assets and liabilities:

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 50,792 

 

 

22,441 

 

 

 

 

Materials, supplies and fuel

 

 (3,232) 

 

 

(2,209)

 

 

 

 

Other current assets

 

 (9,246) 

 

 

(8,674)

 

 

 

 

Accounts payable

 

 (24,421) 

 

 

(14,248)

 

 

 

 

Accrued retirement benefits

 

 947 

 

 

1,572 

 

 

 

 

Other current liabilities

 

 (25,097) 

 

 

(27,419)

 

 

 

 

Other deferred assets

 

 (491) 

 

 

(1,288)

 

 

 

 

Other regulatory assets

 

 (801) 

 

 

9,880 

 

 

 

 

Other deferred liabilities

 

 (1,348) 

 

 

(7,495)

 

 

Net Cash from Operating Activities

 

 37,518 

 

 

52,718 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

Additions to utility plant (excluding AFUDC-equity)

 

 (59,357) 

 

 

(66,843)

 

 

 

 

Customer advances for construction

 

 (749) 

 

 

654 

 

 

 

 

Contributions in aid of construction

 

 6,890 

 

 

15,951 

 

 

 

 

Investments and other property - net

 

 103 

 

 

40 

 

 

Net Cash used by Investing Activities

 

 (53,113) 

 

 

(50,198)

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

Proceeds from issuance of long-term debt, net of costs

 

 - 

 

 

12,432 

 

 

 

 

Retirement of long-term debt

 

 (3,391) 

 

 

(3,129)

 

 

 

 

Dividends paid

 

 (50,000) 

 

 

(39,000)

 

 

Net Cash used by Financing Activities

 

 (53,391) 

 

 

(29,697)

 

 

 

 

 

 

 

 

 

 

 

 

Net Decrease in Cash and Cash Equivalents

 

 (68,986) 

 

 

(27,177)

 

 

Beginning Balance in Cash and Cash Equivalents

 

 201,202 

 

 

65,887 

 

 

Ending Balance in Cash and Cash Equivalents

$

 132,216 

 

$

38,710 

 

 

 

 

 

 

 

 

 

 

 

 

Supplemental Disclosures of Cash Flow Information:

 

 

 

 

 

 

 

 

Cash paid during period for:

 

 

 

 

 

 

 

 

 

Interest

$

 71,187 

 

$

71,276 

 

 

 

 

Income taxes

$

 1 

 

$

 

 

 

Significant non-cash transactions:

 

 

 

 

 

 

 

 

 

Accrued construction expenses as of March 31,

$

 48,812 

 

$

72,179 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

13


NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

Common

 

Common

 

Other

 

 

 

 

Other

 

Total

 

 

Stock

Stock

 

Paid-in

 

Retained

 

 Comprehensive  

 

 Shareholder's 

 

 

Shares

 

  Amount

 

Capital

 

 Earnings 

 

Income (Loss)

 

 Equity 

December 31, 2011

1,000 

 

$

 

$

2,308,219 

 

$

544,874 

 

$

(4,117)

 

$

2,848,977 

 

Net Loss

 - 

 

 

 - 

 

 

 - 

 

 

(1,316)

 

 

 - 

 

 

(1,316)

 

Change in compensation retirement benefits liability

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

and amortization (net of taxes $(32))

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

63 

 

 

63 

 

Dividends Declared

 - 

 

 

 - 

 

 

 - 

 

 

(39,000)

 

 

 - 

 

 

(39,000)

March 31, 2012

1,000 

 

$

 

$

2,308,219 

 

$

504,558 

 

$

(4,054)

 

$

2,808,724 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 1,000 

 

$

 1 

 

$

 2,308,211 

 

$

 618,612 

 

$

 (4,506) 

 

$

2,922,318 

 

Net Income

 - 

 

 

 - 

 

 

 - 

 

 

 5,445 

 

 

 - 

 

 

 5,445 

 

Change in compensation retirement benefits liability

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

and amortization (net of taxes $(54))

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 97 

 

 

 97 

 

Dividends Declared

 - 

 

 

 - 

 

 

 - 

 

 

 (50,000) 

 

 

 - 

 

 

 (50,000) 

March 31, 2013

1,000 

 

$

 

$

2,308,211 

 

$

574,057 

 

$

(4,409)

 

$

2,877,860 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

14


SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

March 31,

 

 

 

 

2013 

 

2012 

 

 

OPERATING REVENUES:

 

 

 

 

 

 

 

 

Electric

$

 172,627 

 

$

169,806 

 

 

 

Gas

 

 39,729 

 

 

45,922 

 

 

Total Operating Revenues

 

 212,356 

 

 

215,728 

 

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

 

Fuel for power generation

 

 41,717 

 

 

36,486 

 

 

 

Purchased power

 

 39,902 

 

 

35,585 

 

 

 

Gas purchased for resale

 

 37,620 

 

 

31,617 

 

 

 

Deferral of energy - electric - net

 

 (19,335) 

 

 

(12,670)

 

 

 

Deferral of energy - gas - net

 

 (14,375) 

 

 

(1,240)

 

 

 

Energy efficiency program costs

 

 1,878 

 

 

3,651 

 

 

 

Other operating expenses

 

 35,805 

 

 

36,432 

 

 

 

Maintenance

 

 6,831 

 

 

9,453 

 

 

 

Depreciation and amortization

 

 27,341 

 

 

25,872 

 

 

 

Taxes other than income

 

 6,295 

 

 

5,863 

 

 

Total Operating Expenses

 

 163,679 

 

 

171,049 

 

 

OPERATING INCOME

 

 48,677 

 

 

44,679 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

Interest expense

 

 

 

 

 

 

 

 

(net of AFUDC-debt: $294 and $416)

 

 (15,525) 

 

 

(16,973)

 

 

 

Interest expense on regulatory items

 

 (25) 

 

 

(186)

 

 

 

AFUDC-equity

 

 523 

 

 

519 

 

 

 

Other income

 

 1,140 

 

 

2,183 

 

 

 

Other expense

 

 (1,248) 

 

 

(1,335)

 

 

Total Other Income (Expense)

 

 (15,135) 

 

 

(15,792)

 

 

Income Before Income Tax Expense

 

 33,542 

 

 

28,887 

 

 

 

 

 

 

 

 

 

 

 

Income tax expense

 

 11,638 

 

 

 10,243 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

 21,904 

 

 

18,644 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income:

 

 

 

 

 

 

 

Change in compensation retirement benefits liability and amortization

 

 

 

 

 

 

 

(Net of taxes $(31) and $(23) in 2013 and 2012, respectively)

 

 59 

 

 

42 

 

 

 

 

 

 

 

 

 

 

COMPREHENSIVE INCOME

$

 21,963 

 

$

18,686 

 

 

 

 

 

 

 

 

 

 

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

 

15


SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

 

 

 

 

 

2013 

 

2012 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets: 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

 85,280 

 

$

60,786 

 

 

 

Accounts receivable less allowance for uncollectible accounts:

 

 

 

 

 

 

 

 

2013 - $953; 2012 - $1,126

 

 118,326 

 

 

124,464 

 

 

 

Materials, supplies and fuel, at average cost

 

 52,615 

 

 

60,662 

 

 

 

Intercompany income taxes receivable

 

 10,351 

 

 

10,351 

 

 

 

Deferred income taxes

 

 18,770 

 

 

21,589 

 

 

 

Other current assets

 

 16,268 

 

 

11,633 

 

 

Total Current Assets

 

 301,610 

 

 

289,485 

 

 

 

 

 

 

 

 

 

 

 

 

Utility Property:

 

 

 

 

 

 

 

 

Plant in service

 

 3,677,762 

 

 

3,667,487 

 

 

 

Construction work-in-progress

 

 126,767 

 

 

140,168 

 

 

 

 

Total

 

 3,804,529 

 

 

3,807,655 

 

 

 

Less accumulated provision for depreciation

 

 1,286,870 

 

 

1,277,866 

 

 

 

 

Total Utility Property, Net

 2,517,659 

 

 

2,529,789 

 

 

 

 

 

 

 

 

 

 

 

 

Investments and other property, net

 

 6,836 

 

 

6,499 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Charges and Other Assets:

 

 

 

 

 

 

 

 

Regulatory assets

 

 320,432 

 

 

328,755 

 

 

 

Regulatory asset for pension plans

 

 138,843 

 

 

140,268 

 

 

 

Other deferred charges and assets

 

 11,811 

 

 

21,477 

 

 

Total Deferred Charges and Other Assets

 

 471,086 

 

 

490,500 

 

 

 

 

 

 

 

 

 

 

 

 

TOTAL ASSETS

$

 3,297,191 

 

$

3,316,273 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Continued)

 

16


 

SIERRA PACIFIC POWER COMPANY

 

 

 CONSOLIDATED BALANCE SHEETS

 

 

(Dollars in Thousands, Except Share Amounts)

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

 

 

 

 

 

2013 

 

2012 

 

 

LIABILITIES AND SHAREHOLDER'S EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

 

 

Current maturities of long-term debt (Note 4)

$

 250,267 

 

$

250,235 

 

 

 

Accounts payable

 

 90,697 

 

 

106,415 

 

 

 

Accounts payable, affiliated companies

 

 22,387 

 

 

21,534 

 

 

 

Accrued expenses

 

 26,464 

 

 

32,936 

 

 

 

Deferred energy (Note 3)

 

 17,421 

 

 

50,763 

 

 

 

Other current liabilities

 

 14,368 

 

 

13,655 

 

 

Total Current Liabilities

 

 421,604 

 

 

475,538 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt (Note 4)

 

 928,851 

 

 

928,990 

 

 

 

 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

 

 

Deferred income taxes

 

 473,937 

 

 

465,508 

 

 

 

Deferred investment tax credit

 

 8,577 

 

 

8,850 

 

 

 

Accrued retirement benefits

 

 98,956 

 

 

98,676 

 

 

 

Regulatory liabilities

 

 228,886 

 

 

227,287 

 

 

 

Other deferred credits and liabilities

 

 75,681 

 

 

72,688 

 

 

Total Deferred Credits and Other Liabilities

 

 886,037 

 

 

873,009 

 

 

 

 

 

 

 

 

 

 

 

 

Shareholder's Equity:

 

 

 

 

 

 

 

 

Common stock, $3.75 par value; 20,000,000 shares authorized

 

 

 

 

 

 

 

 

 

1,000 shares issued and outstanding for 2013 and 2012

 

 4 

 

 

 

 

 

Other paid-in capital

 

 1,111,266 

 

 

1,111,266 

 

 

 

Retained deficit

 

 (49,082) 

 

 

(70,986)

 

 

 

Accumulated other comprehensive loss

 

 (1,489) 

 

 

(1,548)

 

 

Total Shareholder's Equity

 

 1,060,699 

 

 

1,038,736 

 

 

 

 

 

 

 

 

 

 

 

 

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY

$

 3,297,191 

 

$

3,316,273 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Concluded)

 

17


SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

 

 

 

 

For the Three Months Ended,

 

 

 

 

 

March 31,

 

 

 

 

 

2013 

 

2012 

 

 

CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

Net Income

$

 21,904 

 

$

 18,644 

 

 

 

Adjustments to reconcile net income to net cash from operating activities:

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 27,341 

 

 

 25,872 

 

 

 

 

Deferred taxes and deferred investment tax credit

 

 11,707 

 

 

 3,537 

 

 

 

 

AFUDC-equity

 

 (523) 

 

 

 (519) 

 

 

 

 

Deferred energy

 

 (33,343) 

 

 

 (13,184) 

 

 

 

 

Amortization of other regulatory assets

 

 19,441 

 

 

 20,668 

 

 

 

 

Other, net

 

 2,099 

 

 

 2,249 

 

 

 

Changes in certain assets and liabilities:

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 17,331 

 

 

 8,869 

 

 

 

 

Materials, supplies and fuel

 

 8,047 

 

 

 1,335 

 

 

 

 

Other current assets

 

 (4,635) 

 

 

 (4,564) 

 

 

 

 

Accounts payable

 

 (3,198) 

 

 

 (17,675) 

 

 

 

 

Accrued retirement benefits

 

 280 

 

 

 367 

 

 

 

 

Other current liabilities

 

 (5,757) 

 

 

 (5,388) 

 

 

 

 

Other deferred assets

 

 (772) 

 

 

 (314) 

 

 

 

 

Other regulatory assets

 

 (1,578) 

 

 

 (5,716) 

 

 

 

 

Other deferred liabilities

 

 (1,787) 

 

 

 (4,214) 

 

 

Net Cash from Operating Activities

 

 56,557 

 

 

 29,967 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

 

Additions to utility plant (excluding AFUDC-equity)

 

 (38,591) 

 

 

 (48,974) 

 

 

 

 

Customer advances for construction

 

 120 

 

 

 (838) 

 

 

 

 

Contributions in aid of construction

 

 6,680 

 

 

 10,101 

 

 

 

 

Investments and other property - net

 

 8 

 

 

 8 

 

 

Net Cash used by Investing Activities

 

 (31,783) 

 

 

 (39,703) 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

 

Proceeds from issuance of long-term debt, net of costs

 

 - 

 

 

 (1,441) 

 

 

 

 

Retirement of long-term debt

 

 (280) 

 

 

 (166) 

 

 

 

 

Dividends paid

 

 - 

 

 

 (20,000) 

 

 

Net Cash used by Financing Activities

 

 (280) 

 

 

 (21,607) 

 

 

 

 

 

 

 

 

 

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

 

 24,494 

 

 

 (31,343) 

 

 

Beginning Balance in Cash and Cash Equivalents

 

 60,786 

 

 

 55,195 

 

 

Ending Balance in Cash and Cash Equivalents

$

 85,280 

 

$

 23,852 

 

 

 

 

 

 

 

 

 

 

 

 

Supplemental Disclosures of Cash Flow Information:

 

 

 

 

 

 

 

 

Cash paid during period for:

 

 

 

 

 

 

 

 

 

Interest

$

 15,780 

 

$

 15,944 

 

 

 

Significant non-cash transactions:

 

 

 

 

 

 

 

 

 

Accrued construction expenses as of March 31,

$

 12,450 

 

$

 13,671 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

18


SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

Common

 

Common

 

Other

 

 

 

 

 Other 

 

Total

 

 

Stock

 

Stock

 

Paid-In

 

Retained

 

 Comprehensive 

 

 Shareholder's 

 

 

Shares

 

Amount

 

Capital

 

 Deficit 

 

 Income (Loss)

 

 Equity 

December 31, 2011

1,000 

 

$

 

$

1,111,262 

 

$

(135,340)

 

$

(1,384)

 

$

974,542 

 

Net Income

 - 

 

 

 - 

 

 

 - 

 

 

18,644 

 

 

 - 

 

 

18,644 

 

Change in compensation retirement benefits liability

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

and amortization (net of taxes $(23))

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

42 

 

 

42 

 

Dividends Declared

 - 

 

 

 - 

 

 

 - 

 

 

(20,000)

 

 

 - 

 

 

(20,000)

March 31, 2012

1,000 

 

$

 

$

1,111,262 

 

$

(136,696)

 

$

(1,342)

 

$

973,228 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

1,000 

 

$

 

$

1,111,266 

 

$

(70,986)

 

$

(1,548)

 

$

1,038,736 

 

Net Income

 - 

 

 

 - 

 

 

 - 

 

 

 21,904 

 

 

 - 

 

 

 21,904 

 

Change in compensation retirement benefits liability

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

and amortization (net of taxes $(31))

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 59 

 

 

 59 

March 31, 2013

1,000 

 

$

 

$

1,111,266 

 

$

(49,082)

 

$

(1,489)

 

$

1,060,699 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

19


CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both utility

(1)    Organization and non-utility operations are as follows:

Basis of Presentation

The consolidated financial statements includeOperations


Nevada Power Company, together with its subsidiaries (collectively, the accounts"Company"), is a wholly owned subsidiary of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC,("NV Energy"), a holding company that also owns Sierra Pacific Communications, LandsPower Company ("Sierra Pacific") and certain other subsidiaries. The Company is a United States 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 Sierra,Berkshire Hathaway Energy Company ("Berkshire Hathaway Energy"), formerly known as MidAmerican Energy Holdings Company. Berkshire Hathaway Energy is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. Berkshire Hathaway Energy is a consolidated subsidiary of Berkshire Hathaway Inc., NVE Insurance Company, Inc. and Sierra Gas Holding Company.  All intercompany balances and transactions

The unaudited Consolidated Financial Statements have been eliminatedprepared in consolidation.

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 Consolidated Financial Statements as of March 31, 2014 and for the three-month periods ended March 31, 2014 and 2013. Certain amounts in the prior period Consolidated Statement of Operations have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported net income. The results of operations for the three-month period ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year.


The preparation of consolidated financial statementsthe unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities.  These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statementsunaudited Consolidated Financial Statements and the reported amounts of certain revenuesrevenue and expenses during the reporting period. Actual results couldmay differ from these estimates.

                In the opinionestimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessaryNotes to present fairly the consolidated financial position, results of operations and cash flows for the periods shown.  These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statementsConsolidated Financial Statements included in the 2012Company's Annual Report on Form 10-K.

                The results of operations and cash flows of NVE, NPC and SPPC10-K for the three monthsyear ended December 31, 2013 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2013, are not necessarily indicative of the results to be expected for the full year.

2014.


(2)    New Accounting Policies

Consolidations of VIEs

To identify potential variable interests, management reviewed contracts under leases, long-term purchase power contracts, tolling contracts and jointly owned facilities.  The Utilities identified certain long-term purchase power contracts that could be defined as variable interests.  However, the Utilities are not the primary beneficiary as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.  The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers are unable to deliver power.  However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism.  As of March 31, 2013, the carrying amount of assets and liabilities in the Utilities’ balance sheets that relate to their involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.

Recent Accounting Standards Update

      Other Comprehensive Income (ASU 220)

In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income.  Pronouncements


In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2013-04, which amends FASB reinstated certain portionsAccounting Standards Codification 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 deferred amendment.  The reinstated amendmentobligation is applied prospectivelyfixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as well as other information about those obligations. This guidance is effective for NVEinterim and the Utilities as ofannual reporting periods beginning after December 15, 2013. The Company adopted this guidance on January 1, 2013.2014. The adoption of this guidance doesdid not have a material impact on the presentationCompany's disclosures included within Notes to Consolidated Financial Statements.


6



(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the financial statementsfollowing (in millions):
 As of
 March 31, December 31,
 2014 2013
Utility plant in-service:   
Generation$3,821
 $3,789
Distribution2,960
 2,936
Transmission1,751
 1,743
General and intangible plant659
 645
Utility plant in-service9,191
 9,113
Accumulated depreciation and amortization(2,286) (2,217)
Utility plant in-service, net6,905
 6,896
Other non-regulated, net of accumulated depreciation and amortization4
 3
 6,909
 6,899
Construction work-in-progress75
 93
Property, plant and equipment, net$6,984
 $6,992

(4)    Regulatory Matters

Energy Efficiency Implementation Rates

The PUCN's final order approving the merger between Berkshire Hathaway Energy and NV Energy stipulated that the Company will not seek recovery of any lost revenue for NVEcalendar year 2014 in an amount that exceeds 50% of the lost revenue that the Company could otherwise request. As a result, the Company has deferred revenue recognition for energy efficiency implementation rates collected and the Utilities.

      Balance Sheet Offsetting Disclosures (ASU 210)

In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance current disclosures regarding offsetting (netting)has recorded a liability of assets and liabilities$3 million on the face of the financial statements.  The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position.  The scope of this amendment includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements.  The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance does not have a material impact on the disclosure requirements for NVE and the Utilities.

20


NOTE 2.SEGMENT INFORMATION

The Utilities operate three regulated business segments, NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC.  Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada by SPPC.  Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada.  Other information includes amounts below the quantitative thresholds for separate disclosure.

Operational information of the different business segments is set forth below based on the nature of products and services offered.  NVE evaluates performance based on several factors, of which the primary financial measure is business segment gross margin.  Gross margin, which the Utilities calculate as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of the Utilities.  See Note 1, Summary of Significant Accounting Policies, of the 2012 Form 10-K for further information regarding energy efficiency program costs.  

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

Three Months Ended

 

 

 

March 31, 2013

 

NVE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

NVE Other

 

NPC Electric

 

SPPC Total

 

SPPC Electric

 

SPPC Gas

Operating Revenues

$

584,222 

 

$

 

$

371,863 

 

$

212,356 

 

$

172,627 

 

$

39,729 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy Costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel for power generation

 

147,248 

 

 

 - 

 

 

105,531 

 

 

41,717 

 

 

41,717 

 

 

 - 

 

Purchased power

 

121,310 

 

 

 - 

 

 

81,408 

 

 

39,902 

 

 

39,902 

 

 

 - 

 

Gas purchased for resale

 

37,620 

 

 

 - 

 

 

 - 

 

 

37,620 

 

 

 - 

 

 

37,620 

 

Deferred energy

 

(79,065)

 

 

 - 

 

 

(45,355)

 

 

(33,710)

 

 

(19,335)

 

 

(14,375)

Energy efficiency program costs

 

9,845 

 

 

 - 

 

 

7,967 

 

 

1,878 

 

 

1,878 

 

 

 - 

Total Costs

$

236,958 

 

$

 - 

 

$

149,551 

 

$

87,407 

 

$

64,162 

 

$

23,245 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Margin

$

347,264 

 

$

 

$

222,312 

 

$

124,949 

 

$

108,465 

 

$

16,484 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other operating expenses

 

104,672 

 

 

1,475 

 

 

67,392 

 

 

35,805 

 

 

 

 

 

 

Maintenance

 

24,906 

 

 

 - 

 

 

18,075 

 

 

6,831 

 

 

 

 

 

 

Depreciation and amortization

 

96,002 

 

 

 - 

 

 

68,661 

 

 

27,341 

 

 

 

 

 

 

Taxes other than income

 

16,476 

 

 

222 

 

 

9,959 

 

 

6,295 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income (Loss)

$

105,208 

 

$

(1,694)

 

$

58,225 

 

$

48,677 

 

 

 

 

 

 

Three Months Ended

 

 

 

March 31, 2012

 

NVE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

NVE Other

 

NPC Electric

 

SPPC Total

 

SPPC Electric

 

SPPC Gas

Operating Revenues

$

611,420 

 

$

 

$

395,688 

 

$

215,728 

 

$

169,806 

 

$

45,922 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy Costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel for power generation

 

117,035 

 

 

 - 

 

 

80,549 

 

 

36,486 

 

 

36,486 

 

 

 - 

 

Purchased power

 

117,116 

 

 

 - 

 

 

81,531 

 

 

35,585 

 

 

35,585 

 

 

 - 

 

Gas purchased for resale

 

31,617 

 

 

 - 

 

 

 

 

 

31,617 

 

 

 - 

 

 

31,617 

 

Deferred energy

 

(11,739)

 

 

 - 

 

 

2,171 

 

 

(13,910)

 

 

(12,670)

 

 

(1,240)

Energy efficiency program costs

 

 19,425 

 

 

 - 

 

 

 15,774 

 

 

 3,651 

 

 

 3,651 

 

 

 - 

Total Costs

$

273,454 

 

$

 - 

 

$

180,025 

 

$

93,429 

 

$

63,052 

 

$

30,377 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Margin

$

337,966 

 

$

 

$

215,663 

 

$

122,299 

 

$

106,754 

 

$

15,545 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other operating expenses

 

103,601 

 

 

707 

 

 

66,462 

 

 

36,432 

 

 

 

 

 

 

Maintenance

 

32,526 

 

 

 - 

 

 

23,073 

 

 

9,453 

 

 

 

 

 

 

Depreciation and amortization

 

90,862 

 

 

 - 

 

 

64,990 

 

 

25,872 

 

 

 

 

 

 

Taxes other than income

 

14,509 

 

 

192 

 

 

8,454 

 

 

5,863 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income (Loss)

$

96,468 

 

$

(895)

 

$

52,684 

 

$

44,679 

 

 

 

 

 

 

21


NOTE 3.REGULATORY ACTIONS

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

The following deferred energy amounts were included in the consolidated balance sheetsConsolidated Balance Sheets as of March 31, 2013 (dollars in thousands):

 

 

 

March 31, 2013

 

 

 

 

NVE Total

 

NPC Electric

 

SPPC Electric

 

SPPC Gas

 

 

Deferred Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative Balance as of December 31, 2012

$

(151,880)

 

$

(101,117)

   

$

(32,693)

 

$

(18,070)

 

 

 

2013 Amortization

 

55,053 

 

 

30,313 

 

 

11,296 

 

 

13,444 

 

 

 

2013 Deferred Energy Under Collections  (1) 

 

25,498 

 

 

16,896 

 

 

7,795 

 

 

807 

 

 

Deferred Energy Balance at March 31, 2013 - Subtotal

$

(71,329)

 

$

(53,908)

 

$

(13,602)

 

$

(3,819)

 

 

Reinstatement of deferred energy (effective 6/07, 10 years)

 

99,113 

 

 

99,113 

 

 

 - 

 

 

 - 

 

 

 

Total Deferred Energy

$

27,784 

 

$

45,205 

 

$

(13,602)

 

$

(3,819)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred energy

$

84,120 

 

$

84,120 

 

$

 - 

 

$

 - 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred energy

 

(56,336)

 

 

(38,915)

 

 

(13,602)

 

 

(3,819)

 

 

 

Total Net Deferred Energy

$

27,784 

 

$

45,205 

 

$

(13,602)

 

$

(3,819)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting

 

 

Policies, Deferred Energy Accounting, of the Notes to Financial Statements in the 2012 Form 10-K. 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pending Regulatory Actions

 Nevada Power2014. In February 2014, the Company

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

In March 2013, NPC filed an application forwith the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEIRenergy efficiency implementation rate. The Company proposed to suspend collection of the energy efficiency implementation rate on October 1, 2014, and EEPRdefer implementation of a new energy efficiency implementation rate elements.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the table above.  The March 2013 application includes the following changes in revenue requirement (dollars in millions):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Anticipated

 

Requested

 

Present

 

$ Change in

 

 

 

 

 

Effective

 

Revenue

 

Revenue

 

Revenue

 

 

 

 

 

Date

 

Requirement

 

Requirement

 

Requirement

 

 

Revenue Requirement Subject To Change:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REPR(1)

Oct. 2013

 

$

28.4 

 

$

38.7 

 

$

(10.3)

 

 

 

TRED(1)

Oct. 2013

 

 

15.7 

 

 

15.9 

 

 

(0.2)

 

 

 

EEPR Base(1)

Oct. 2013

 

 

45.9 

  

 

32.6 

  

 

13.3 

 

 

 

EEPR Amortization(1)

Oct. 2013

 

 

(29.9)

 

 

9.0 

  

 

(38.9)

 

 

 

EEIR Base

Oct. 2013

 

 

15.1 

  

 

10.6 

  

 

4.5 

 

 

 

EEIR Amortization

Oct. 2013

 

 

(6.7)

  

 

10.7 

 

 

(17.4)

 

 

 

 

Total Revenue Requirement

 

 

$

68.5 

 

$

117.5 

 

$

(49.0)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the

 

 

 

revenues collected.  As a result, such programs have no effect on Operating or Net Income.

 

Sierra Pacific Power Company

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

In March 2013, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEPR and EEIR rate elements.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above.The March 2013 application includes the following changes in revenue requirement includes the following (dollars in millions):

22


until January 1, 2015.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Anticipated

 

Requested

 

Present

 

$ Change in

 

 

 

 

 

Effective

 

Revenue

 

Revenue

 

Revenue

 

 

 

 

 

Date

 

Requirement

 

Requirement

 

Requirement

 

 

Revenue Requirement Subject To Change:

 

 

 

 

 

 

 

 

 

 

 

 

 

REPR (1)

Oct. 2013

 

$

42.3 

 

$

44.4 

 

$

(2.1)

 

 

 

TRED (1)

Oct. 2013

 

 

7.4 

 

 

6.3 

 

 

1.1 

 

 

 

EEPR Base (1)

Oct. 2013

 

 

6.0 

 

 

5.6 

  

 

0.4 

 

 

 

EEPR Amortization (1)

Oct. 2013

 

 

(2.2)

  

 

1.8 

  

 

(4.0)

 

 

 

EEIR Base

Oct. 2013

 

 

5.6 

  

 

 4.7 

  

 

0.9 

 

 

 

EEIR Amortization

Oct. 2013

 

 

1.1 

  

 

 1.9 

  

 

(0.8)

 

 

 

 

Total Revenue Requirement

 

 

$

60.2 

 

$

64.7 

 

$

(4.5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 (1) 

Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the

 

 

 

revenues collected.  As a result, such programs have no effect on Operating or Net Income.

 


SPPC

2013 Nevada Gas DEAA and REPR Rate Filings

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

FERC Matters

   NPC

      NPC 2012 FERC Transmission Rate Case


In October 2012, NPCMay 2013, the Company, along with Sierra Pacific, filed an application with the FERC to resetestablish single system transmission and ancillary service rates that were last set in 2003.rates. The combined filing requested incremental rate changes requested in this filing would result in an overall annual revenue increaserelief of $11.3 million.  In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases$17 million annually to be effective January 1, 2013.  All rates are2014. On August 5, 2013, the FERC granted the companies' request for a rate effective date of January 1, 2014 subject to final approval byrefund, and set the FERC.  However, atcase for hearing or settlement discussions. On January 1, 2014, the Company implemented the filed rates in this case subject to refund as set forth in FERC's order. As of March 31, 2014, the Company accrued $3 million for amounts subject to rate refund, which is included in customer deposits and other on the Consolidated Balance Sheets. At this time management is unable to determine the final revenue impact of the case.

 SPPC 

      SPPC 2012 FERC Transmission Rate Case

In October 2012, SPPC filed an application with the FERC to reset transmission


(5)    Employee Benefit Plans

The Company is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and ancillary service ratesa supplemental executive retirement plan and a restoration plan (collectively, "Non-Qualified Pension Plans") that were last set in 2007provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and 2003, respectively.  The rate changes requested in this filing would result in an overall annual revenue increase of $3.2 million.  In December 2012, FERC issued an order which suspendedCafeteria Plan provides certain rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013.  All rates are subject to final approval by the FERC.However, at this time management is unable to determine the final revenue impactpostretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of the case.

23


NOTE 4.LONG-TERM DEBT

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

 

 

 

 

 

 

 

 

March 31,

 

December 31,

 

 

 

 

 

 

 

 

2013 

 

2012 

Long-Term Debt:

Stated Rate

 

 

Maturity Date

 

Consolidated

 

NVE Holding Co.

 

NPC

 

SPPC

 

Consolidated

 

NVE Holding Co.

 

NPC

 

SPPC

Secured Debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General and Refunding Mortgage Securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NPC Series L

5.875 

%

 

2015 

 

$

250,000 

 

$

 

$

250,000 

 

$

 

$

250,000 

 

$

 

$

250,000 

 

$

 

 

NPC Series M

5.950 

%

 

2016 

 

 

210,000 

 

 

 

 

210,000 

 

 

 

 

210,000 

 

 

 

 

210,000 

 

 

 

 

NPC Series N

6.650 

%

 

2036 

 

 

370,000 

 

 

 

 

370,000 

 

 

 

 

370,000 

 

 

 

 

370,000 

 

 

 

 

NPC Series O

6.500 

%

 

2018 

 

 

325,000 

 

 

 

 

325,000 

 

 

 

 

325,000 

 

 

 

 

325,000 

 

 

 

 

NPC Series R       

6.750 

%

 

2037 

 

 

350,000 

 

 

 

 

350,000 

 

 

 

 

350,000 

 

 

 

 

350,000 

 

 

 

 

NPC Series S          

6.500 

%

 

2018 

 

 

500,000 

 

 

 

 

500,000 

 

 

 

 

500,000 

 

 

 

 

500,000 

 

 

 

 

NPC Series U

7.375 

%

 

2014 

 

 

125,000 

 

 

 

 

125,000 

 

 

 

 

125,000 

 

 

 

 

125,000 

 

 

 

 

NPC Series V

7.125 

%

 

2019 

 

 

500,000 

 

 

 

 

500,000 

 

 

 

 

500,000 

 

 

 

 

500,000 

 

 

 

 

NPC Series X

5.375 

%

 

2040 

 

 

250,000 

 

 

 

 

250,000 

 

 

 

 

250,000 

 

 

 

 

250,000 

 

 

 

 

NPC Series Y

5.450 

%

 

2041 

 

 

250,000 

 

 

 

 

250,000 

 

 

 

 

250,000 

 

 

 

 

250,000 

 

 

 

 

SPPC Series M

6.000 

%

 

2016 

 

 

450,000 

 

 

 

 

 

 

450,000 

 

 

450,000 

 

 

 

 

 

 

450,000 

 

 

SPPC Series P

6.750 

%

 

2037 

 

 

251,742 

 

 

 

 

 

 

251,742 

 

 

251,742 

 

 

 

 

 

 

251,742 

 

 

SPPC Series Q

5.450 

%

 

2013 

 

 

250,000 

 

 

 

 

 

 

250,000 

 

 

250,000 

 

 

 

 

 

 

250,000 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable Rate Debt (Secured

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

by General and Refunding

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mortgage Securities)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NPC IDRB Series 2000A

 

 

 

2020 

 

 

98,100 

 

 

 

 

98,100 

 

 

 

 

98,100 

 

 

 

 

98,100 

 

 

 

 

NPC PCRB Series 2006

 

 

 

2036 

 

 

37,700 

 

 

 

 

37,700 

 

 

 

 

37,700 

 

 

 

 

37,700 

 

 

 

 

NPC PCRB Series 2006A

 

 

 

2032 

 

 

37,975 

 

 

 

 

37,975 

 

 

 

 

37,975 

 

 

 

 

37,975 

 

 

 

 

SPPC PCRB Series 2006A

 

 

 

2031 

 

 

58,200 

 

 

 

 

 

 

58,200 

 

 

58,200 

 

 

 

 

 

 

58,200 

 

 

SPPC PCRB Series 2006B

 

 

 

2036 

 

 

75,000 

 

 

 

 

 

 

75,000 

 

 

75,000 

 

 

 

 

 

 

75,000 

 

 

SPPC PCRB Series 2006C

 

 

 

2036 

 

 

81,475 

 

 

 

 

 

 

81,475 

 

 

81,475 

 

 

 

 

 

 

81,475 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Senior Notes

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NVE Senior Notes

6.250 

%

 

2020 

 

 

315,000 

 

 

315,000 

 

 

 

 

 

 

315,000 

 

 

315,000 

 

 

 

 

 

 

NVE Term Loan

2.810 

%

 

2014 

 

 

195,000 

 

 

195,000 

 

 

 

 

 

 

195,000 

 

 

195,000 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Obligations under capital leases

 

 

 

 

 

 

40,872 

 

 

 

 

39,268 

 

 

1,604 

 

 

44,258 

 

 

 

 

42,908 

 

 

1,350 

Unamortized bond premium and discount, net

 

 

 

 

 

 

1,519 

 

 

 

 

(9,578)

 

 

11,097 

 

 

1,631 

 

 

 

 

(9,827)

 

 

11,458 

Current maturities

 

 

 

 

 

 

(481,342)

 

 

 

 

(231,075)

 

 

(250,267)

 

 

(356,283)

 

 

 

 

(106,048)

 

 

(250,235)

Total Long-Term Debt

 

 

 

 

 

$

4,541,241 

 

$

510,000 

 

$

3,102,390 

 

$

928,851 

 

$

4,669,798 

 

$

510,000 

 

$

3,230,808 

 

$

928,990 

Substantially all utility plant is subjectCompany. Amounts attributable to the liens of the NPC Indenture and the SPPC Indenture under which their respective General and Refunding Mortgage bonds are issued.

NOTE 5. FAIR VALUE OF FINANCIAL INSTRUMENTS

The March 31, 2013 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments.  As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2012 Form 10-K, investments held in Rabbi Trust continues to be considered Level 1 in the fair value hierarchy.

The total fair value of NVE’s consolidated long-term debt at March 31, 2013 is estimated to be $5.9 billion based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities.  The total fair value was estimated to be $5.9 billion as of December 31, 2012.

The total fair value of NPC’s consolidated long-term debt at March 31, 2013, is estimated to be $4.0 billion based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities.  The total fair value was estimated to be $4.1 billion at December 31, 2012.

The total fair value of SPPC’s consolidated long-term debt at March 31, 2013, is estimated to be $1.3 billion based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities.  The total fair value was estimated to be $1.3 billion as of December 31, 2012

24


NOTE 6.RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities.  NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPCCompany were allocated from NV Energy based upon the current, or in the case of the retirees, previous, employment location. Certain grandfatheredOffsetting regulatory assets and union employees are covered underliabilities have been recorded related to the amounts not yet recognized as a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees.   A summary of the componentscomponent of net periodic pensionbenefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive income.



7



Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
 As of
 March 31, December 31,
 2014 2013
Qualified Pension Plan:   
Other assets$11
 $13
    
Non-Qualified Pension Plans:   
Customer deposits and other(4) (4)
Other long-term liabilities(8) (8)
    
Other Postretirement Plans:   
Other long-term liabilities(7) (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, coal, and other postretirement costscommodity price risk as it has an obligation to serve retail customer load in its 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 are 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, options, swaps and other agreements, to effectively secure future supply or sell future production, generally at fixed prices. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, the Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

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

The following table, which 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  
  Deposits and Long-term  
  Other Liabilities Total
As of March 31, 2014      
Commodity liabilities(1)
 $(8) $(27) $(35)
       
As of December 31, 2013      
Commodity liabilities(1)
 $(9) $(38) $(47)

(1)
The Company's commodity derivatives not designated as hedging contracts are included in regulated rates, and as of March 31, 2014 and December 31, 2013, a regulatory asset of $35 million and $47 million, respectively, was recorded related to the derivative liability of $35 million and $47 million, respectively.

8




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 March 31, December 31,
 Measure 2014 2013
Electricity salesMegawatt hours 4
 4
Natural gas purchasesDecatherms 129
 118

Credit Risk

The Company extends unsecured credit to 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. Credit risk may be concentrated to the extent that one or more groups of 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 default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with the counterparty.

The Company analyzes the financial condition of each significant wholesale counterparty before entering into any transactions, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, the Company enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains 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 months ended March 31 follows.  This summary is based on a December 31, measurement date (dollars in thousands):

NVE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension Benefits

 

 

Other Postretirement Benefits

 

 

 

For the Three Months Ended March 31,

 

 

For the Three Months Ended March 31,

 

 

 

2013 

 

 

2012 

 

 

2013 

 

 

2012 

Service cost

 

$

5,132 

 

$

4,406 

 

$

660 

 

$

595 

Interest cost

 

 

9,303 

 

 

10,228 

 

 

1,677 

 

 

1,905 

Expected return on plan assets

 

 

(12,708)

 

 

(12,447)

 

 

(1,687)

 

 

(1,563)

Amortization of prior service cost

 

 

(720)

 

 

(724)

 

 

(952)

 

 

(987)

Amortization of net loss

 

 

4,797 

 

 

3,473 

 

 

890 

 

 

731 

Net periodic benefit cost

 

$

5,804 

 

$

4,936 

 

$

588 

 

$

681 

 

 

 

 

 

 

 

 

 

 

 

 

 

The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 33.8% and 33.2%, respectively.

NPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension Benefits

 

Other Postretirement Benefits

 

 

 

For the Three Months Ended March 31,

 

 

For the Three Months Ended March 31,

 

 

 

2013 

 

 

2012 

 

 

2013 

 

 

2012 

Service cost

 

$

2,761 

 

$

2,358 

 

$

389 

 

$

350 

Interest cost

 

 

4,453 

 

 

4,881 

 

 

556 

 

 

602 

Expected return on plan assets

 

 

(6,270)

 

 

(6,237)

 

 

(631)

 

 

(592)

Amortization of prior service cost

 

 

(453)

 

 

(456)

 

 

(23)

 

 

229 

Amortization of net loss

 

 

2,117 

 

 

1,363 

 

 

289 

 

 

221 

Net periodic benefit cost

 

$

2,608 

 

$

1,909 

 

$

580 

 

$

810 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

SPPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension Benefits

 

Other Postretirement Benefits

 

 

For the Three Months Ended March 31,

 

For the Three Months Ended March 31,

 

 

2013 

 

2012 

 

2013 

 

2012 

Service cost

 

$

1,926 

 

$

1,695 

 

$

251 

 

$

227 

Interest cost

 

 

4,558 

 

 

5,043 

 

 

1,104 

 

 

1,283 

Expected return on plan assets

 

 

(6,162)

 

 

(5,937)

 

 

(1,022)

 

 

(941)

Amortization of prior service cost

 

 

(277)

 

 

(277)

 

 

(933)

 

 

(1,220)

Amortization of net loss

 

 

2,501 

 

 

2,026 

 

 

592 

 

 

504 

Net periodic benefit cost

 

$

2,546 

 

$

2,550 

 

$

(8)

 

$

(147)

 

 

 

 

 

 

 

 

 

 

 

 

 

The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 was 34.4% and 33.0%, respectively.

As discussed in Note 10, Retirement Plan and Postretirement Benefits,recognized credit rating agencies. These derivative contracts may either specifically provide rights to demand cash or other security in the 2012 Form 10-K, NVE offeredevent of a voluntary lump sum pension payoutcredit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to former employees not currentlydemand "adequate assurance," in the event of retirement age but eligible for future benefitsa material adverse change in creditworthiness. These rights can vary by contract and certain retiree participants already receiving benefits under NVE’s pension plan in an effort to reduce NVE’s future pension obligation.by counterparty. As of March 31, 2013, NVE expects to payout an additional $11.0 million in lump sum pension pay outs2014, credit ratings from the pensionthree recognized credit rating agencies were investment grade.


The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features was $4 million. 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.


9



(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 during 2013. 

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


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

The Company's commodity derivative contracts are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which incorporates a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. 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 instruments not only includes counterparty risk, but also the impact of the Company's nonperformance risk on its liabilities, which as of March 31, 2014 and December 31, 2013, had an immaterial impact to the fair value of its derivative instruments. As such, the Company considers its commodity derivative contracts to be valued using Level 3 inputs.

The following table reconciles the beginning and ending balances of the Company's commodity liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the three-month period ended March 31 NVE made no contributions to either(in millions):
 2014
Beginning balance$(47)
Changes in fair value recognized in regulatory assets12
Ending balance$(35)

The Company's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of the plans.  AtCompany's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present time, NVE expects neithervalue of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):
 As of March 31, 2014 As of December 31, 2013
 Carrying Fair Carrying Fair
 Value Value Value Value
        
Long-term debt$3,067
 $3,661
 $3,071
 $3,596


10



(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.

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

Accelerating the plan will requireto 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 funding in 2013 inelectric generating capacity; and
Assuring regulatory procedures that protect reliability and supply and address financial impacts on customer and utility.

In February 2014, the PUCN issued a final order approving draft regulations, subject to meetreview by a Nevada Legislative commission and which must be filed with the minimum funding level requirements defined by the Pension Protection ActSecretary of 2006.  However, NVEState, and the Utilities have included in their 2013 assumptions funding levels similar toregulations became effective March 2014. In May 2014, the 2012 funding.  The amounts to be contributed in 2013 may change subject to market conditions.

25


NOTE 7. COMMITMENTS AND CONTINGENCIES

Environmental

NPC 

      NEICO

NEICO, a wholly-owned subsidiaryCompany filed its Emission Reduction Capacity Replacement Plan proposing, among other items, the retirement of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility.  The site has a reclamation estimate supported by a bond of approximately $4 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs.  Management is continuing to evaluate various options for this property going forward, including reclamation or sale to a third party.

Reid Gardner Generating Station

On 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 generation capacity being retired, as required by Senate Bill No. 123. The Emissions Reduction and Capacity Replacement 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-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 Emissions Reduction and Capacity Replacement Plan, which are subject to PUCN approval.


Reid Gardner Generation Station

In October 4, 2011, NPCthe Company received a request for information from the EPA-RegionEnvironmental Protection Agency Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for NPC’sthe Company's Reid Gardner Generating Station located near Moapa, Nevada. NPC operates the facility and owns Units 1-3.  Unit 4 of the facility is co-owned with the CDWR.  The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant.  NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request.  At this time, NPC cannot predict the impact, if any, associated with this information request.

SPPC 

      Valmy Generating Station

On June 22, 2009, SPPC received a request for information from the EPA-Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada.  SPPC co-owns and operates this coal-fired plant.  Idaho Power Company owns the remaining 50%.  The EPA’sEnvironmental 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 EPAEnvironmental Protection Agency relating to the plant. SPPCThe Company completed its responseresponses to the EPA in December 2009Environmental Protection Agency during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, SPPCthe Company cannot predict the impact, if any, associated with this information request.

   NPC and SPPC

     Regional Haze Rules 

In 2005, the EPA finalized amendments


Legal Matters

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

In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations.  In March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station.  The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015.  In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station Units at a later date.  In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP.For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice.  Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015.On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline for the Reid Gardner Generating Station retrofits so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada.  On March 26, 2013,the  EPA granted reconsideration of the compliance date for the  BART retrofits for Units 1, 2, and 3 at Reid Gardner Generating Station, proposing to extend the compliance date by 18 months, from January 1, 2015, to June 30, 2016. The EPA held a public hearing on April 29, 2013, to accept written and oral comments on this proposed action. The comment period for this action is scheduled to close on May 30, 2013.  

NVE continues to work toward finalizing the retrofit designs for the affected BART units.  NVE has received approval from the PUCN to retire Tracy Generating Station Units 1 and 2, and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2.  NVE intends to also file with the PUCN the request to install SNCRs on Reid Gardner Generating Station Units 1, 2 & 3.  Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units.  NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.

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

26


the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station.  NVE has intervened in this lawsuit.  At this time management is unable to determine the likelihood of success by petitioners in these litigation matters.  An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned. 

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

The comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested a 90-day extension, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners.  In March, 2013, the EPA granted a 90-day extension to August 5, 2013. Prior to the close of the comment period, the EPA is expected to hold public hearings in Arizona.

Given that the lease must be renegotiated by 2019, the timeline for BART installation is unclear,and EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predictat this timethe ultimate financial impact to the Navajo Generating Station operations or what other alternativelegal actions the ownership may decide to take at this time.

      Mercury and Air Toxics Standards (MATS)

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

The final rule does not specifically list control technologies that are required to achieve the MATS emission standards.  Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards.  At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC.  Note that the actual cost will be dependent upon final engineering design.

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

Currently, all four of the units at the Reid Gardner Generating Station, as well as Unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend.  However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.

Other Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.  In addition, NVE and the Utilities may also be subject to future state or federal regulations.  Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites.  This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties.  The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation.  Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility, which may be accelerated by any decision to retire a generating station or other facility.  If remediation activities involve statutory joint and several liability provisions, strict liability or cost recovery of contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties.  In some instances, NVE or the Utilities may share liability associated with contamination with other parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs.  These types of sites/situations are generally managed in the normal course of business operations.

                In 2008, NPC signed an Administrative Orderbusiness. 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 Consent (AOC) as owner and operatorlegal actions, some of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owners and operating agent of Unit No. 4.  Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs.  However, actual costs of work under the AOCwhich assert or may vary significantly once the scope of work is defined and additional site characterization has been completed.

                NVE and the Utilitiesassert claims or seek to continually comply with environmental regulations; however, given the uncertainties involvedimpose fines, penalties and other costs in the federal, statesubstantial amounts and local regulatory environment, future costs to comply may be material.

are described below.

27



11


Litigation Contingencies

NPC 

      Peabody Western Coal Company – Royalty Claim

NPC owns an 11% interest in


November 2005 Land Investors

In 2006, November 2005 Land Investors, LLC ("NLI") purchased from the Navajo Generating Station, which isUnited States through the Bureau of Land Management 2,675 acres of land located in northern Arizona and operated by Salt River. Other participants in the Navajo Generating Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with Salt River and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station which is located in Laughlin, Nevada and was operated by Southern California Edison (SCE) prior to the time it became non-operational on December 31, 2005.

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

In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising outNorth Las Vegas, Nevada. A small portion of the DC Lawsuit.  In July 2008,land is traversed by a 500 kilovolt transmission line owned by the court dismissed all counts against NPC, two without prejudice to their possible re-filing.

In August 2011, all claims in the DC Lawsuit were dismissedCompany and sited pursuant to a settlement agreement amongpre-existing right-of-way grant from the Navajo Nation, Peabody, Salt RiverBureau of Land Management. Subsequent to NLI's purchase, a dispute arose as to whether the Company owed rent and, SCE.  Atif it did, the requestamount 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 Salt River, NPC contributed an immaterial amount towardcontract, inverse condemnation and trespass. The Company counterclaimed for express condemnation of a perpetual easement over the settlementright-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 DC Lawsuit based on its 11% ownership stake inright-of-way corridor. The Company has appealed to the Navajo Generating Station. 

SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station.  NPC has not agreed to contribute to SCE’s portion of the DC Lawsuit settlement.  Management has discussed the matters with SCE, but does not believe the impact of any claim by, or settlement with, SCE will be material to NPC.

     SPPC

        Farad Dam

In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million.  One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume.  Under the terms of the contract with TMWA, SPPC is not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably  acceptable to TMWA or, alternatively, SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.  The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.

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

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

It is not known at this time when the District Court will set hearings for the issues remanded by the Ninth Circuit.Supreme Court. Management cannot assess or predict the outcome orof the case at this time.


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 California Department of Water Resources, alleging that activities at the Reid Gardner Generating Station are causing imminent and substantial harm to the environment and that placement of coal combustion residuals at the on-site landfill constitute "open dumping" in violation of the Resource Conservation and Recovery Act. The complaint also alleges that the Reid Gardner Generating Station is engaged in the unlawful discharge of pollutants in violation of the Clean Water Act. The notice was issued pursuant to the citizen suit provisions of the Resource Conservation and Recovery Act and the Clean Water Act. CDWR was named as a co-defendant in the litigation due to its prior co-ownership in Reid Gardner Generating Station unit 4. The complaint seeks various injunctive remedies, assessment of civil penalties, and reimbursement of plaintiffs' attorney and legal fees and costs. The Company answered the complaint and intends to vigorously defend the suit. Given the stage of the proceeding, management cannot predict the impact to the Company, or estimate the range of the District Court decisions at this time, but they are not expected to be material to SPPC.

   Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.

Other Commitments

   NPC and SPPC

      ON Line TUA

During the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  ON Line has an expected in-service date of no later than December 31, 2013.  The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE’s future lease payments are adjusted for final capital costs, for which the Utilities

loss.

28



12

expect to get regulatory recovery.  For accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of March 31, 2013, capitalized construction costs associated with GBT’s 75% interest of $297.5 million and $17.0 million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.

NOTE 8. EARNINGS PER SHARE (NVE)

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

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

2013 

 

2012 

 

 

 

Basic EPS

 

 

 

 

 

 

 

 

 

Numerator ($000)

 

 

 

 

 

 

 

 

 

 

Net Income

$

21,475 

 

$

12,173 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Denominator

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares outstanding

 

235,193,702 

 

 

235,999,750 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Per Share Amounts

 

 

 

 

 

 

 

 

 

 

Net Income per share - basic

$

0.09 

 

$

0.05 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted EPS

 

 

 

 

 

 

 

 

 

Numerator ($000)

 

 

 

 

 

 

 

 

 

 

Net Income

$

21,475 

 

$

12,173 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Denominator(1)

 

 

 

 

 

 

 

 

 

 

Weighted average number of shares outstanding before dilution

 

235,193,702 

 

 

235,999,750 

  

 

 

 

 

Stock options

 

18,767 

 

 

35,283 

 

 

 

 

 

Non-Employee Director stock plan

 

179,971 

 

 

153,686 

 

 

 

 

 

Employee stock purchase plan

 

10,539 

 

 

10,888 

 

 

 

 

 

Restricted Shares

 

579,000 

 

 

497,750 

 

 

 

 

 

Performance Shares

 

1,023,909 

 

 

829,506 

 

 

 

 

 

Diluted Weighted Average Number of Shares

 

237,005,888 

 

 

237,526,863 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Per Share Amounts

 

 

 

 

 

 

 

 

 

 

Net income per share - diluted

$

0.09 

 

$

0.05 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the prior period.  If the conditions for conversion were met under this plan, 0 and 333,140 shares would be included for the three months ended March 31, 2013 and 2012, respectively.

 

 

NOTE 9.COMMON STOCK AND OTHER PAID-IN CAPITAL

Dividends

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

Declaration Date

Amount

Payable Date

Shareholders of Record Date

February 7, 2013

$

0.19 

March 20, 2013

March 5, 2013

May 8, 2013

$

0.19 

June 19, 2013

June 4, 2013

On May 8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0 million and $20.0 million, respectively.  For the three months ended March 31, 2013, NPC paid dividends to NVE of $50.0 million.

Treasury Stock

NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program.  All shares repurchased are held as treasury stock and may be reissued

29




upon exercise or settlement of the stock compensation award.  Treasury stock is accounted for using the cost method. During the three months ended March 31, 2013, NVE repurchased 197,178 shares of common stock for approximately $3.7 million.  During the three months ended March 31, 2013, NVE re-issued 644,536 treasury shares to satisfy employee benefit plans.

30


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

Forward-Looking Statements and Risk Factors

The information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.  These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking.  These statements are based on management’s beliefs and assumptions and on information currently available to management.  Actual results could differ materially from those contemplated by the forward-looking statements.  In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of NVE, NPC or SPPC (NPC and SPPC are collectively referred to as the “Utilities”) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

Operational Risks

·

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

·

changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, and the impact of energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

·

construction risks, including but not limited to those associated with ON Line, such as difficulty in securing adequate skilled labor, cost and availability of materials and equipment, third-party disputes, equipment failure, engineering and design failure, work accidents, fire or explosions, business interruptions, recovery of possible cost overruns, delay of in-service dates, and pollution and environmental damage;

·

security breaches of our information technology or supervisory control and data systems, or the systems of others  upon which the Utilities rely, whether through cyber-attack, cyber-crime, sabotage, accident or other means, which may affect our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information; 

·

unseasonable or severe weather, drought, wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, seriously impact the Utilities’ ability and/or cost to procure adequate supplies of fuel or purchased power, affect the amount of water available for electric generating plants in the southwestern U.S., and have other adverse effects on our business;

·

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

·

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

·

changes in and/or implementation of FERC and NERC mandatory reliability, security, and other requirements for system infrastructure, which could significantly affect existing and future operations;

·

explosions, fires, accidents, mechanical breakdowns or vandalism that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory, including gas distribution services that the Utilities may rely upon, that can cause unplanned outages, reduce generating output, damage the Utilities’ assets or operations, subject the Utilities to third-party claims for property damage, personal injury or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;

·

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

·

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

·

the effect that any future terrorist attacks, wars, threats of war or pandemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general;

·

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

31


Regulatory/Legislative Risks

·

unfavorable rulings, penalties and findings by the PUCN in rate or other cases, investigations or proceedings, including GRCs, the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution business, renewable energy and energy efficiency recovery programs, and unfavorable rulings, penalties or findings by the FERC in rate or other cases, investigations and proceedings with regard to wholesale power sales and transmission services;

·

the effect of existing or future Nevada or federal laws or regulations affecting the electric industry, including those which could allow additional customers to choose new electricity suppliers, use alternative sources of energy, generate their own electricity, or change the conditions under which they may do so;

·

whether the Utilities can procure, obtain, and/or maintain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada; and

·

changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject or which change the rate of federal or state taxes payable by our shareholders or common stock dividends.

Environmental Risks

·

changes in and/or implementation of environmental laws or regulations, including the imposition of limits on emissions of carbon or other pollutants from electric generating facilities, which could significantly affect the Utilities existing operations as well as our construction program.

Liquidity and Capital Resources Risks

·

whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs)  and/or power, or a ratings downgrade;

·

wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving credit facilities, which may affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

·

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

·

the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly in the event of: volatility in the global credit markets or other problems, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN,  a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;

·

whether NVE's BOD will declare NVE's common stock dividends based on the BOD’s periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions contained in NVE's and the Utilities' agreements;

·

whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act; and

·

further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension and other postretirement plans, which can affect future funding obligations, costs and pension and other postretirement plan liabilities.

Other factors and assumptions not identified above may also have been involved in deriving forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected.  NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.

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NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

In reviewing the agreements filed as exhibits to this Quarterly Report on Form 10-Q, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements.  The agreements contain representations and warranties by each of the parties that are specific to the applicable agreement.  These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;

have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

may apply standards of materiality in a way that is different from what may be viewed as material to investors; and

were made only as of the date of the applicable agreement or such other date or dates as may be specified in such agreements and are subject to more recent developments.

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

NOTE REGARDING STATISTICAL DATA

The statistical data used throughout this 10-Q, other than data relating specifically to NVE and its subsidiaries, are based upon independent industry publications, government publications, reports by market research firms or other published independent sources.   NVE and the Utilities did not commission any of these publications or reports.  These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy or completeness of such information.  While NVE and the Utilities believe that each of these studies and publications is reliable, NVE and the Utilities have not independently verified such data and make no representation as to the accuracy of such information.

33


EXECUTIVE OVERVIEW

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

Critical Accounting Policies and Estimates:

Recent Pronouncements

For each of NVE, NPC and SPPC:

Results of Operations

Analysis of  Cash Flows

Liquidity and Capital Resources

Regulatory Proceedings (Utilities)


NVE’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas.  

General

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

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

The Utilities’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. NPCThe Company is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning.  SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under shortshort- and long termlong-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities.Company. Additionally, the timely recovery of purchased power, and fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of the Utilities. 

OverviewCompany.


The following is management's discussion and analysis of Major Factors Affecting 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

NVE recognized for the First Quarter of 2014 and 2013


Net income for 2014 was $6 million, an increase of $1 million, or 20%, as compared to 2013.
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
  2014 2013 Change
Gross margin (in millions):       
Operating revenue $417
 $370
 $47
13 %
Cost of fuel, energy and capacity 203
 142
 61
43
Gross margin $214
 $228
 $(14)(6)
        
Sales (GWh):       
Residential 1,465
 1,611
 (146)(9)%
Commercial 933
 916
 17
2
Industrial 1,629
 1,635
 (6)
Other 53
 48
 5
10
Total retail 4,080
 4,210
 (130)(3)
Wholesale 5
 14
 (9)(64)
Total sales 4,085
 4,224
 (139)(3)
        
Average number of retail customers (in thousands) 868
 851
 17
2 %
        
Average retail revenue per MWh $99.89
 $86.11
 $13.78
16 %
        
Heating degree days 668
 1,050
 (382)(36)%
Cooling degree days 34
 86
 (52)(60)
        
Sources of energy (GWh):       
Coal 1,228
 473
 755
*
Natural gas 2,269
 3,394
 (1,125)(33)
Total energy generated 3,497
 3,867
 (370)(10)
Energy purchased 811
 643
 168
26
Total 4,308
 4,510
 (202)(4)

*Not meaningful

13




Gross margin decreased $14 million, or 6%, for 2014 compared to 2013 primarily due to:
a decrease in net incomeresidential usage of $21.5$12 million, primarily due to a decrease in heating degree days during the winter;
a decrease in energy efficiency program rate revenues of $5 million, which are offset in operating and maintenance expense; and
a decrease of $2 million in energy efficiency implementation revenues.
The decrease in gross margin was partially offset by:
an increase in transmission rate revenues of $3 million; and
an increase in customer growth of $2 million.

Operating and maintenance expense decreased $17 million, or 17%, for 2014 compared to 2013 primarily due to:
decreased energy efficiency program costs of $5 million, which are fully recovered in operating revenue;
stock compensation costs in 2013 of $5 million;
decreased major outages and planned maintenance expenses at the Higgins and Lenzie Generating Stations of $5 million; and
decreased costs associated with outside consulting services of $2 million.
Depreciation and amortization increased $1 million, or 2%, for 2014 compared to 2013 primarily due to higher plant-in-service.

Allowance for equity funds decreased $2 million for the three months ended March 31, 2013,2014 compared to $12.22013 primarily due to a decrease in construction activity, including ON Line being placed in service in December 2013.

Interest expense, net of allowance for debt funds decreased $2 million, or 4%, for the same period in 2012.  The increase in net income is2014 compared to 2013 primarily due to the following pre-tax items:

An increase in gross margin of $9.3 million; see the Utilities’ respective Results of Operations for further discussion of gross margin;

A decrease in maintenance expense of $7.6 million due to the timing of outages; see the Utilities’ respective Results of Operations for further discussion; and

A decrease in interest expense of $4.6 million primarily due to the redemption of NPC’s 6.5%redemption of $125 million Series U 7.375% General and Refunding Mortgage Notes Series I in April 2012 and an increase in AFUDC-debt.

NVE Transformation

Beginning in 2006, NVE committedDecember 2013.


Other, net increased $1 million for 2014 compared to an energy strategy2013 primarily due to manage resources against our load by constructing/purchasing generating facilities, purchasing and developing renewable energy, encouraging energy efficiency and conservation programs, as well as, expanding our transmission capability in an efforthigher interest income on under collected deferred energy.

Income tax expense increased $1 million, or 33%, for 2014 compared to reduce our reliance on purchased power.  The implementation of this strategy required significant amounts of liquidity and capital.  To meet these capital requirements during the transformation, NVE and the Utilities issued, refinanced and reduced debt which improved credit ratings and decreased interest costs.  At the same time, management worked with the PUCN2013 primarily due to communicate the necessity of investments to better serve our customers, the prudency of costs incurred and the importance of a reasonable and timely return on such investments for our shareholders. 

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

Key Initiatives

The economy in Nevada continues to recover slowly.  While a low growth environment can be challenging, the foundation established in prior years, including establishing energy independence, improving capital structure and liquidity and managing our regulatory environment, has positioned the Utilities to operate in this environment.  However, NVE and the Utilities continue to implement and develop key initiatives that collectively may further our ability to increase our common stock dividend, strengthen our capital structure and consider new investment opportunities.  These initiatives should enable us to contain operating and

income before income tax expense.

34



maintenance costs while effectively managing our regulatory environmentLiquidity and continuing to promote and improve a safe and reliable work environment.   These key initiatives are discussed below.

Continuous Improvement ofSafety 

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

Construction of ON Line and One Company Merger

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

Capital Resources

Ability to dispatch energy jointly throughout the state;

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

Ability to optimize its generating and transmission facilities to benefit its customers; and

The opportunity for NVE to merge NPC and SPPC (the “One Company” merger).  A merger application is expected to be filed with the PUCN and FERC in June 2013.


Empower Customers through Focused Service and Efficiency Programs

NV Energize is a NVE project that includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management.  The NV Energize capabilities will allow NVE to help customers better manage their usage with the most cost-effective mix of pricing, service, efficiency and conservation options. 

As of March 31, 2014, the Company's total net liquidity was $599 million consisting of $99 million in cash and cash equivalents and $500 million of revolving credit facility availability.

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2014 and 2013 the installation of the Smart Meters is nearly complete. 

were $33 million and $37 million, respectively. The NV Energize system provides more convenience forchange was primarily due to a one-time bill credit paid to retail customers and is achieving operating savings through both automated meter reading and the elimination annually of approximately 1 million trips to customers’ premises to process service requests.  The system also enables NVE to launch new customer programs.  Recruitment of participants for a trial of a combination of time based rates, supporting technology and education options is now underway.  New detailed customer usage reports have been integrated into our web self-service capability, and customers can also request alerts on their billing information.  An enhanced air conditioning demand response program was launched in the fourth quarter.   It is designed to provide energy market based rebates for specific event participation and also includes an energy efficiency management capability.  Similar programs for commercial customers are under development.

Managing Generation Portfolio Within Environmental Compliance

As discussed in more detail in Note 7, Commitments and Contingencies, of the Notes to Financial Statements, certain generating stations of NVE are affected under EPA’s Regional Haze Rules.  The implementation costs of the Regional Haze Rules are significant.  Therefore, NVE must balance the cost of implementing the retrofits associated with the Regional Haze Rule withmerger between Berkshire Hathaway Energy and NV Energy, intercompany transactions related to ON Line, and increased rent payments related to the effect currentON Line transmission use agreement, partially offset by reduced refunds to customers for previously over-collected deferred energy costs and future load requirements, retirements of generating stations, including the effects of NVision discussed below, and plant outages will have on its ability to serve its customers reliably. 

  Investment opportunities

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

Proposed Legislationan increase in Nevada

The Nevada Legislature is currently in session and is expected to complete its session in the second quarter of 2013.  The most significant legislation under consideration that would directly impact NVE is Senate Bill 123 (SB 123), which is a bill supported by NVE as part of its NVision initiative.  NVision is a comprehensive planenergy rates.


Investing Activities

Net cash flows from investing activities for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and natural gas-fired plants and the implementation of further demand response programs.  At the time of this filing, management cannot predict whether SB 123 will be adopted in its present or an amended form, or its ultimate impact on NVE and the Utilities.

NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. and Other Subsidiaries

NVE (Holding Company)

The operating results of NVE primarily reflect those of NPC and SPPC, discussed later.  The holding company’s (stand alone) operating results included approximately $6.3 million and $6.3 million of long term debt interest costs for the three monthsthree-month periods ended March 31, 2014 and 2013 and 2012, respectively. 

35


For the period ended March 31, 2013, NPC paid $50.0 million in dividends to NVE. On May 8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0were $(49) million and $20.0$(53) million, respectively.

Other Subsidiaries

Other subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.

ANALYSIS OF CASH FLOWS

NVE’s cash flows decreased during the three months ended March 31, 2013, compared to the same period in 2012, The change was primarily due to an increase in contributions in aid of construction and customer advances.


14




Financing Activities

Net cash used by financing activities, offset partially by an increase in cash from operating activitiesflows for the three-month periods ended March 31, 2014 and a decrease in cash used by investing activities.

Cash from Operating Activities -2013 were $(11) million and $(53) million, respectively. The increase in cash from operating activitieschange was primarily due to increased cash flows from accounts receivablea decrease in dividends, partially offset by $5 million of debt tendered in 2014 as a result of the merger between Berkshire Hathaway Energy and NV Energy and higher balances at December 31, 2012, comparedpayments for capital and financial lease obligations.


Ability to balances at December 31, 2011, dueIssue Debt

The Company's ability to higher BTGR rates resulting from NPC’s 2011 GRC which were effective January 1, 2012.  Also contributing to the increase was a reduction in refunds to customers for previously over collected BTER balances, a reduction in coal and gas purchases, and the receipt of approximately $9.0 million in insurance proceeds related to a previous claim.  These increases were offsetissue debt is primarily impacted by an under collection of energy costs in 2013 as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates.

Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to the decrease in construction activity related to the NV Energize project, partially offset by the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, also related to the NV Energize project.

Cash used by Financing Activities - Cash used byits financing activities increasedprimarily due to anincrease in dividends to shareholders, a reduction in drawsauthority from the NPC’sPUCN. As of March 31, 2014, the Company has financing authority from the PUCN consisting of authority 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 andof up to $1.3 billion. The Company's revolving credit facility contains a financial maintenance covenant which the repurchase of common stock, which may be reissued to satisfy future equity compensation costs.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

NVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC.  The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and,Company was in the case of SPPC, natural gas.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest.  Another significant use of cash is the refunding of previously over-collected BTER amounts from customers.Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes and economic conditions.  Available liquiditycompliance with as of March 31, 2013 was as follows (in millions):

 

Available Liquidity as of March 31, 2013 (in millions)

 

 

 

 

 

 

 

NVE

 

NPC

 

SPPC

 

 

Cash and Cash Equivalents

 

$

27.4 

 

$

132.2 

 

$

85.3 

 

 

 

Balance available on Revolving Credit Facilities(1)

 

 

N/A

 

 

497.3 

 

 

243.7 

 

 

 

 

 

 

 

27.4 

 

 

629.5 

 

 

329.0 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

(1)

 

As of May 7, 2013, NPC and SPPC had approximately $497.3 million and $243.7 million available under their revolving credit facilities, which includes reductions in availability for letters of credit.

 

NVE and the Utilities’ attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, the Utilities may use their revolving credit facilities in order to meet their liquidity needs.  Alternatively, depending on the usage of their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NVE has no debt maturities in 2013.However, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020 prior to ON Line’s commercial operation date expected by December 31, 2013 and its $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014.  SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature in September 2013.  To meet these long term maturing debt obligations, the Utilities intend to use a combination of internally generated funds, the Utilities’ revolving credit facilities, and/or the issuance of long term debt.  The Utilities’ credit ratings on their senior secured debt remains at investment grade (see Credit Ratings below).  NVE and the Utilities have not recently experienced any limitations in the credit markets, nor do we expect any for the remainder of 2013.  However, disruption in the banking and capital markets not specifically related to NVE and the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.  

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

36


However, if energy costs rise at a rapid rate, or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less.  In order to maintain sufficient liquidity under such circumstances, NVE and the Utilities may be required to delay capital expenditures, re-finance debt or issue equity at NVE.  Additionally, if deemed prudent, the Utilities may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs.  Currently, the Utilities are not operating under a PUCN approved hedging plan.  Hedging transactions may have a material impact on the Utilities’ cash flows, unless recovered in rates in a timely manner. 

As of May8, 2013, NVE has approximately $22.9 million payable of debt service obligations remaining for 2013, which it intends to fund through dividends from subsidiaries.  (See Factors Affecting Liquidity-Dividends from Subsidiaries, below).  For the three months ended March 31, 2013, NPC paid dividends to NVE of approximately $50.0 million.  On May8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0 million and $20.0 million, respectively.

NVE designs operating and capital budgets to control operating costs and capital expenditures.  In addition to operating expenses, NVE has continuing commitments for capital expenditures for construction, environmental compliance, improvement and maintenance of facilities.  As discussed, in Note 12, Commitments and Contingencies of the 2012 Form 10-K, capital projects include NPC’s purchase of Reid Gardner Generating Station Unit No. 4 from CDWR.  The purchase is expected to be completed mid 2013 for approximately $47.1 million, subject to final approval by the FERC.

During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in NVE’s 2012 Form 10-K.

Factors Affecting Liquidity

   Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence and liens, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four-quarter period on a pro forma basis is at least 1.50 to 1.00 and the ratio of consolidated total indebtedness to consolidated capitalization does not exceed .70 to 1.00.  Under these covenant restrictions, as of March 31, 2013, NVE (consolidated) would be allowed to incur up to $3.2 billion of additional indebtedness.  The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.  NPC’s and SPPC’s Ability to Issue Debt sections further discuss their limitations on their ability to issue debt.

   Effect of Holding Company Structure

As of March 31, 2013, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: a $195 million Term Loan due 2014; and$315 million of unsecured 6.25% Senior Notes due 2020.

Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors.  Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

As of March 31, 2013, NVE, NPC, SPPC and their subsidiaries had approximately $5.0 billion of debt and other obligations outstanding, consisting of approximately $3.3 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510.0 million of debt at the holding company and other subsidiaries.  Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE.  Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of March 31, 2013, there were no dividend restrictions imposed on the Utilities by the PUCN.

In addition, certain financing agreements entered into bycontain covenants which are currently suspended as the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid.  As a result of the Utilities’ credit rating on their senior secured debt being rated investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as such debt remains investment grade by both rating agencies.  In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.”  Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts.  If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.

Credit Ratings

The liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt.  On April 30, 2013, Fitch upgraded NVE’s corporate credit ratings from BB to BB+, and for NPC and SPPC, from BB+ to investment grade BBB-.  NPC’s and SPPC’sCompany's senior secured debt is rated investment grade. However, if the Company's senior secured debt ratings fall below investment grade by three NRSRO’s: Fitch, Moody’seither 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 S&P.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 senior debtavailability and terms under which the Company has access to external financing depends on a variety of factors, including the Company's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items, such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into the Company's regulated retail rates. Expenditures for certain assets may ultimately include acquisitions of existing assets.

Forecasted capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, are approximately $380 million for the year ended December 31, 2014 and are as follows (in millions):
  2014
   
Generation development $222
Distribution 75
Transmission system investment 30
Other 53
Total $380

Contractual Obligations

As of March 31, 2014, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2013.

Regulatory Matters

The Company is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2013, and new regulatory matters occurring in 2014.


15



In May 2014, the Company filed the Emissions Reduction Capacity Replacement Plan 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 generation capacity being retired, as required by SB 123. The Emissions Reduction and Capacity Replacement 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-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 Emissions Reduction and Capacity Replacement Plan, which are subject to PUCN approval. The impacts of the Emissions Reduction Capacity Replacement Plan to the Company's 2014 forecasted capital expenditures are included in the Future Uses of Cash previously discussed.

In May 2014, the Company filed a general rate case with the PUCN requesting an annual increase of $21 million, or an average price increase of 1%. An order is expected by the end of 2014 and, if approved, the new rates would be effective January 1, 2015.

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 Berkshire Hathaway Energy and NV Energy stipulated that the Company would obtain PUCN authorization prior to participating in an energy imbalance market. The amendment reflects the Company's participation in the energy imbalance market that is being established by the California Independent System Operator. An order on the filing is expected in August 2014. The filing requests the PUCN to determine that the amended energy supply plan balances the objectives of minimizing the cost of supply and retail price volatility; maximizes the reliability of supply over the remaining term of the plan; optimizes the value of the overall supply portfolio of the Company for the benefit of bundled retail customers; and does not contain any features or mechanisms that the PUCN finds would impair the restoration or the creditworthiness of the Company.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state, local and international agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Refer to "Liquidity and Capital Resources" for discussion of the Company's forecasted environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2013.

Clean Air Act Regulations

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


16



Mercury and Air Toxics Standards

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

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

Water Quality Standards

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

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

Collateral and Contingent Features

Debt of the Company is rated by credit rating agencies. Assigned credit ratings are as follows:

Rating Agency

Fitch(1)

Moody’s(2)

S&P(3)

NVE

Sr. Unsecured Debt

     BB+

      Ba1

     BB+

NPC

Sr. Secured Debt

     BBB+*

      Baa1*

     BBB+*

SPPC

Sr. Secured Debt

     BBB+*

      Baa1*

     BBB+*

*

Investment grade

(1)

Fitch’s lowest level of “investment grade” credit rating is BBB-.

(2)

Moody’s lowest level of “investment grade” credit rating is Baa3.

(3)

S&P’s lowest level of “investment grade” credit rating is BBB-.

37


Fitch’s, Moody’s and S&P’sbased on each rating outlooksagency's assessment of the Company's ability to, in general, meet the obligations of its issued debt. The credit ratings are stable for NVE, NPC and SPPC.  

A security rating is not a recommendation to buy, sell or hold securities.  Securitysecurities, and there is no assurance that a particular credit rating will continue for any given period of time.


17




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 subjecttied to revision and withdrawal at any time by the assigning rating organization.  Each security rating agency has its own methodology for assigningcredit ratings and accordingly, eachincrease 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 should be evaluatedagencies. These agreements may either specifically provide rights to demand cash or other security in the contextevent of a credit rating downgrade ("credit-risk-related contingent features") or provide the applicable methodology, independentlyright for counterparties to demand "adequate assurance," in the event of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

Energy Supplier Matters

With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP.  The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change which includes ain creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2014, credit ratings from the three recognized credit rating downgrade of NPC and SPPC, may allow the counterparty to requestagencies were investment grade. If all credit-risk-related contingent features or adequate financial assurance which, if not provided within three business days, could cause a default.  Most contracts and confirmationsprovisions for purchased power havethese agreements had been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  A default must be declared within 30 days of the event, giving rise to the default becoming known.  A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received.  The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time.  The net mark-to-market valuetriggered as of March 31, 2013 for all suppliers continuing to provide power under a WSPP agreement2014, the Company would approximate a $94.6 million payment or obligation to NPC.  No amounts would be due to or from SPPC.  These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. 

   Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily mean a credit rating downgrade below investment grade.  Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.   

Gas transmission service is secured under FERC tariffs or custom agreements.  These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.  NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.   As of March 31, 2013, the maximum amount$56 million of additional collateral. The Company's collateral NPC would be requiredrequirements could fluctuate considerably due to post under these contractsmarket price volatility, changes in the eventcredit ratings, changes in legislation or regulation, or other factors. Refer to Note 7 of credit rating downgrades was approximately $87.2 million.  Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade. 

   Financial Gas Hedges

The Utilities may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of the 2012Company's collateral requirements specific to the Company's derivative contracts.


New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K NPC’s and SPPC’s Financing Transactions, the availability under the Utilities’ revolving credit facilities is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities.  Currently, there are no negative mark-to-market exposures that would impact borrowings of the Utilities.  If deemed prudent, the Utilities may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   Cross Default Provisions

None of the Utilities’ financing agreements contains a cross default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements.  Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in an event of default by NVE upon an event of default by the Utilities under their respective financing agreements.  In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due.  Most of these default provisions (other than ones relating to a failure to pay other

38


indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of approximately $5.4 million during the three months ended March 31, 2013, compared to a net loss of approximately $1.3 million for the same period in 2012.

For the periodyear ended MarchDecember 31, 2013, NPC paid $50.0 million in dividends to NVE.  On May 8, 2013, NPC declared a dividend of $30.0 million to NVE.

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

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which NPC calculates as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of NPC.  For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

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

39


 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

Operating Revenues:

 

$

371,863 

 

$

395,688 

 

$

(23,825)

 

(6.0)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy Costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel for power generation

 

 

105,531 

 

 

80,549 

 

 

24,982 

 

31.0 

%

 

 

Purchased power

 

 

81,408 

 

 

81,531 

 

 

(123)

 

(0.2)

%

 

 

Deferred energy

 

 

(45,355)

 

 

2,171 

 

 

(47,526)

 

(2,189.1)

%

 

Energy efficiency program costs

 

 

7,967 

 

 

15,774 

 

 

(7,807)

 

(49.5)

%

 

 

Total Costs

 

$

149,551 

 

$

180,025 

 

$

(30,474)

 

(16.9)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Margin

 

$

222,312 

 

$

215,663 

 

$

6,649 

 

3.1 

%

Gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012. The increase is primarily due to $2.6 million related to a slight increase in the BTGR effective rate, a $2.3 million net increase in usage primarily due to milder weather in 2012 as indicated in the table below, and approximately $1.4 million due to customer growth.

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period.  A degree day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F.  For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1.  In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.

The following table shows the HDDs and CDDswithin NPC’s service territory:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

 

2012 

 

Variance

 

% Change

 

NPC

 

 

 

 

 

 

 

 

 

 

 

 

 

Heating

 

1,050 

 

 

924 

 

126 

 

 

13.6 

%

 

 

Cooling

 

86 

 

 

41 

 

45 

 

 

109.8 

%

The causes for2013. There have been no significant changes in specific lines comprising the resultsCompany's assumptions regarding critical accounting estimates since December 31, 2013.


Item 3.
Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A of operations for NPCthe Company's Annual Report on Form 10-K for the respective periods are provided below (dollars in thousands except for amounts per unit):

Operating Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues:

2013 

 

2012 

 

Variance

 

% Change

 

 

Residential

$

191,894 

 

$

194,489 

 

$

(2,595)

 

(1.3)

%

 

 

Commercial

 

79,561 

 

 

87,735 

 

 

(8,174)

 

(9.3)

%

 

 

Industrial

 

88,477 

 

 

99,914 

 

 

(11,437)

 

(11.4)

%

 

 

 

Retail revenues

 

359,932 

 

 

382,138 

 

 

(22,206)

 

(5.8)

%

 

 

Other

 

11,931 

 

 

13,550 

 

 

(1,619)

 

(11.9)

%

 

 

 

Total Operating Revenues

$

371,863 

 

$

395,688 

 

$

(23,825)

 

(6.0)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retail sales in thousands of MWhs

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

1,611 

 

 

1,536 

 

 

75 

 

4.9 

%

 

 

Commercial

 

916 

 

 

957 

 

 

(41)

 

(4.3)

%

 

 

Industrial

 

1,635 

 

 

1,652 

 

 

(17)

 

(1.0)

%

 

Retail sales in thousands of MWhs

 

4,162 

 

 

4,145 

 

 

17 

 

0.4 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average retail revenue per MWh

$

86.48 

 

$

92.19 

 

 

(5.71)

 

(6.2)

%

NPC’s retail revenues decreased for the three monthsyear ended MarchDecember 31, 2013, as compared2013. The Company's exposure to the same period in 2012 primarily duemarket risk and its management of such risk has not changed materially since December 31, 2013. Refer to $22.1 million in rate decreases largely due to NPC’s various BTER and DEAA quarterly updates (See Note 3, Regulatory Actions, 6 of the Notes to theConsolidated Financial Statements in the 2012Item 1 of this Form 10-K), and $7.7 million from decreases in EEPR rates effective January 1, 2013. Thesedecreases were offset by an increase of $6.5 million resulting from increased residential usage, primarily due to an increase in HDDs.

40


For the three months ended March 31, 2013, the average number of retail customers increased slightly by 0.6%, consisting of an increase in residential, commercial and industrial customers of 0.6%, 1.1% and 0.7%, respectively, compared to the same period in the prior year.

Electric operating revenue – other10-Q for the three months ended March 31, 2013, compared to the same period in 2012, did not change materially. 

Energy Costs

Energy Costs include fuel for generation and purchased power.  Energy costs are dependent upon several factors which may vary by season or period.  As a result, NPC’s usage and average cost per MWh of fuel for generation versus purchased power to meet demand can vary significantly.  Factors that may affect energy costs include, but are not limited to:

weather

generation efficiency

plant outages

total system demand

resource constraints

transmission constraints

natural gas constraints

long-term contracts

mandated power purchases; and

volatility of commodity prices

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

Energy Costs

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel for power generation

$

105,531 

 

$

80,549 

 

$

24,982 

 

31.0 

%

 

 

Purchased power

 

81,408 

 

 

81,531 

 

 

(123)

 

(0.2)

%

 

Total Energy Costs

$

186,939 

 

$

162,080 

 

$

24,859 

 

15.3 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

MWhs

 

 

 

 

 

 

 

 

 

 

 

 

 

   MWhs Generated (in thousands)

 

3,675 

 

 

3,287 

 

 

388 

 

11.8 

%

 

 

   Purchased Power (in thousands)

 

643 

 

 

1,026 

 

 

(383)

 

(37.3)

%

 

Total MWhs

 

4,318 

 

 

4,313 

 

 

 

0.1 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average cost per MWh

 

 

 

 

 

 

 

 

 

 

 

 

 

   Average fuel cost per MWh of Generated Power

$

28.72 

 

$

24.51 

 

$

4.21 

 

17.2 

%

 

 

   Average cost per MWh of Purchased Power

$

126.61 

 

$

79.46 

 

$

47.14 

 

59.3 

%

 

 

   Average total cost per MWh

$

43.29 

 

$

37.58 

 

$

5.71 

 

15.2 

%

Energy Costs and the average total cost per MWh increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to an increase in costs associated with higher natural gas prices partially offset by a decrease in the volume of purchased power which is typically more expensive than generated power.

Fuel for generation costs increased for the three months ended March 31, 2013, compared to the same period in 2012.  Approximately $13.5 million of the increase is due to an increase in natural gas prices and approximately $11.5 million of the increase is due to an increase in volume.Volume increased due to continued reliance on internal generation to satisfy load requirements. 

Purchased power costs decreased slightly for the three months ended March 31, 2013, compared to the same period in 2012.  Approximately $65.5 million of the decrease was due to a decrease in volume.  The decrease was largely offset by an increase of approximately $65.4 million in the cost of purchased power.  As the volume of purchased power decreases, the remaining contracts consist primarily of higher cost renewable energy contracts and other long term fixed capacity contracts which are increasing the average cost per unit.  Also contributing to the increase in the average cost per unit is the increase in the volume of power sales which are offset in purchased power. 

Deferred Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred energy

$

(45,355)

 

$

2,171 

 

$

(47,526)

 

(2,189.1)

%

41


Deferred Energy for the three months ended March 31, 2013 include amortizations of $(27.3) million, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the 2013 deferred energy balance are under-collections of amounts recoverable in rates of $(18.0) million. 

Deferred Energy for the three months ended March 2012 include amortizations of previous over-collections of $(35.2) million, partially offset by over-collections of amounts recoverable in rates of $37.3 million. 

Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates.  To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs.  Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs.  Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred.  Reference Note 3, Regulatory Actions,disclosure of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Other Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy efficiency program costs

$

7,967 

 

$

15,774 

 

$

(7,807)

 

(49.5)

%

 

Other operating expenses

$

67,392 

 

$

66,462 

 

$

930 

 

1.4 

%

 

Maintenance

$

18,075 

 

$

23,073 

 

$

(4,998)

 

(21.7)

%

 

Depreciation and amortization

$

68,661 

 

$

64,990 

 

$

3,671 

 

5.6 

%

For the three months ended March 31, 2013 energy efficiency program costs decreased compared to the same period in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013.  Reference Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortization rate filings.

Other operating expense increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $2.7 million increase in stock compensation costs, offset by a $1.3 million decrease in telecommunications, meter reading and meter replacement software costs, and $0.7 million in lower pension and benefit costs.

Maintenance expense decreased for the threemonths ended March 31, 2013, compared to the same period in 2012, primarily due to $5.3 million in planned maintenance and outages at the Silverhawk, Higgins, Reid Gardner and Lenzie Generating Stations in 2012.

Depreciation and amortization increased slightly for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service. 

Interest Expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

Interest expense

 

 

 

 

 

 

 

 

 

 

 

 

(net of AFUDC-debt: $1,837 and $1,179)

$

51,259 

 

$

54,405 

 

$

 (3,146) 

 

(5.8)

%

Interest expense decreased for the three months ended March 31, 2013, compared to the same period in 2012 due to a $2.2 million decrease in interest cost primarily due to the redemption of the 6.5% General and Refunding Mortgage Notes, Series I in April 2012 and an increase in AFUDC-debt of $0.7 million. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 4, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.

Other Income (Expense)

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest income (expense) on regulatory items

$

(802)

 

$

(2,016)

 

$

1,214 

 

(60.2)

%

 

AFUDC-equity

$

2,366 

 

$

1,413 

 

$

953 

 

67.4 

%

 

Other income

$

2,404 

 

$

1,709 

 

$

695 

 

40.7 

%

 

Other expense

$

(2,401)

 

$

(1,346)

 

$

(1,055)

 

78.4 

%

Interest expense on regulatory items decreased for the three months ended March 31, 2013, compared to the same period in 2012, due to a $1.6 million decrease in interest on deferred energy as a result of lower over-collected  balances in 2013, and a decrease of $0.7 million in estimated interest expense accrued on the deferred gain on NPC’s wireless towers sold in 2011 pending final accounting approval by the PUCN in 2012, offset by $1.3 million net decrease of interest income due to lower regulatory asset balances.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K.

42


AFUDC-equity increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to various construction projects. 

Other income increased for the three months ended March 31, 2013, compared to the same period in 2012, by several items, all of which were immaterial. 

Other expense increased for the three months ended March 31, 2013, compared to the same period in 2012,by several items, all of which were immaterial. 

Analysis of Cash Flows

NPC’s cash flows decreased during the three months ended March 31, 2013, compared to the same period in 2012, due to a decrease in cash from operating activities and an increase in cash used by investing and financing activities.

Cash from Operating Activities - The decrease in cash from operating activities was primarily due to an under collection of energy costs in 2013 as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates, and reduced energy efficiency rates.  These decreases were partially offset by increased cash flows from accounts receivable as a result of higher balances at December 31, 2012, compared to balances at December 31, 2011, due to higher BTGR rates resulting from NPC’s 2011 GRC which were effective January 1, 2012.  Further offsetting the decrease in cash from operating activities was the reduction in refunds to customers for previously over collected BTER balances. 

Cash used by Investing Activities - The increase in cash used by investing activities was primarily due to the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, related to the NV Energize project, partially offset by decreased construction activity related to the NV Energize project.

Cash used by Financing Activities - Cash used by financing activities increased primarily due to an increase in dividends paid to NVE and a reduction in draws from the NPC revolving credit facility.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness.  Another significant use of cash is the refunding of previously over-collected amounts from customers.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.  Available liquidityCompany's derivative positions as of March 31, 2013 was as follows (in millions):

2014.

Available Liquidity as of March 31, 2013 (in millions)

NPC

Cash and Cash Equivalents

$

132.2 

Balance available on Revolving Credit Facility(1)

497.3 

$

629.5 

(1)

As of May 7, 2013, NPC had approximately $497.3 million available under its revolving credit facility which includes reductions for letters of credits.


NPC attempts to maintain its cash

Item 4.    Controls and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, NPC may use its revolving credit facility in order to meet its liquidity needs.  Alternatively, depending onProcedures

At the usageend of the revolving credit facility, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. 

NPC is required to redeem approximately $98.1 millionperiod covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected no later than December 31, 2013 and its $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014.  To meet these maturing debt obligations, NPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt.  As of May 8, 2013, NPC has no borrowings on its revolving credit facility, notCompany's management, including letters of credit.  NPC’s credit ratings on its senior secured debt remains at investment grade (see Credit Ratings below).   NPC has not recently experienced any limitations in the credit markets, nor does NPC expect any significant limitations for the remainder of 2013.  However, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

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

43


However, if energy costs rise at a rapid rate or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Chief Financial Gas Hedges, the amount of liquidity available NPC could be significantly less.  In order to maintain sufficient liquidity under such circumstances, NPC may be required to delay capital expenditures, re-finance debt or receive capital contributions from NVE.

During the three months ended March 31, 2013, NPC paid dividends to NVE of $50.0 million.  OnMay 8, 2013, NPC declared a dividend to NVE of $30.0 million.

NPC designs operating and capital budgets to control operating costs and capital expenditures.  In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, environmental compliance, improvement and maintenance of facilities.  As discussed in Note 12, Commitments and ContingenciesOfficer (principal financial officer), of the 2012 Form 10-K, capital projects include NPC’s purchase of Reid Gardner Generating Station Unit No. 4 from CDWR.  The purchase is expected to be completed mid 2013 for approximately $47.1 million, subject to final approval by the FERC.

 During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in NPC’s 2012 Form 10-K.

Factors Affecting Liquidity

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements, its revolving credit facility agreement, and the terms of certain NVE debt.  As of March 31, 2013, the most restrictiveeffectiveness of the factors below is the PUCN authority.  As such, NPC may issue up to $725.0 million in long-term debt, in addition to the use of its existing credit facility.  However, depending on NVE’s or SPPC’s issuance of long-term debt or the usedesign and operation of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting NPC’s ability to issue debt are further detailed below:

a.

Financing authority from the PUCN - As of March 31, 2013, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725.0 million; (2) to refinance up to approximately $422.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion. 

b.

Financial covenants within NPC’s financing agreements – Under the NPC Credit Agreement, NPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.00.  Based on March 31, 2013 financial statements, NPC was in compliance with this covenant and could incur up to $2.8 billion of additional indebtedness.

All other financial covenants contained in NPC’s financing agreements are suspended as NPC’s senior secured debt is currently rated investment grade.  However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; and

c.

Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.2 billion.

   Ability to Issue General and Refunding Mortgage Securities

To the extent that NPC has the ability to issue debt under the most restrictive covenants in its and NVE’s financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the NPC Indenture.

The NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada.  As of March 31, 2013,$3.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.6 billion of General and Refunding Mortgage Securities as of March 31, 2013.  That amount is determined on the basis of:

1.

70% of net utility property additions; and/or

2.

the principal amount of retired General and Refunding Mortgage Securities.

Property additions include plant in service.  Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.

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

Credit Ratings

The liquidity of NPC, the cost and availability of borrowing by NPC under the NPC Credit Agreement, the potential exposure of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for NPC’s debt.  On April 30, 2013, Fitch upgraded NPC’s corporate credit rating from BB+ to investment grade BBB-.  NPC’s senior secured debt is rated investment grade by three NRSRO’s:  Fitch, Moody’s and S&P.  The senior secured debt credit ratings are as follows:

Rating Agency

Fitch(1)

Moody’s(2)

S&P(3)

NPC

Sr. Secured Debt

     BBB+*

      Baa1*

     BBB+*

*

Investment grade

(1)

Fitch’s lowest level of “investment grade” credit rating is BBB-.

(2)

Moody’s lowest level of “investment grade” credit rating is Baa3.

(3)

S&P’s lowest level of “investment grade” credit rating is BBB-.

44


Fitch’s, Moody’s and S&P’s rating outlooksare stable for NPC.    

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

Energy Supplier Matters

With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP.  The WSPP agreement is posted on the WSPP website.

Under these contracts, a material adverse change, which includes a credit rating downgrade, in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  A default must be declared within 30 days of the event giving rise to the default becoming known.  A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received.  The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time.  The net mark-to-market value as of March 31, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $94.6 million payment or obligation to NPC.  These contracts qualify for the normal purchases and normal sales scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. 

   Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade.  Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances.  Forward physical gas supplies are purchased under index based pricing terms, and as such, do not carry forward mark-to-market exposure.  

Gas transmission service is secured under FERC tariffs or custom agreements.  These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.  NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.   As of March 31, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million.  Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade. 

   Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Financial Statements in the 2012 Form 10-K,  NPC’s Financing Transactions, the availability under the NPC’s revolving credit facility is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the credit facility.  Currently, there are no negative mark-to-market exposures that would impact borrowings of NPC.  If deemed prudent, NPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   Cross Default Provisions

None of the financing agreements of NPC contains a cross default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of its financing agreements.  In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due.  Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.

45


Sierra Pacific Power Company

RESULTS OF OPERATIONS

SPPC recognized net income of $21.9 million for the three months ended March 31, 2013, compared to net income of $18.6 million for the same period in 2012. 

During the three months ended March 31, 2012, SPPC did not pay dividends to NVE. On May 8, 2013, SPPC declared a dividend of $20.0 million to NVE.

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

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which SPPC calculates as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of SPPC.  For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

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

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

Operating Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric

$

172,627 

 

$

169,806 

 

$

2,821 

 

1.7 

%

 

 

 

Gas

 

39,729 

 

 

45,922 

 

 

(6,193)

 

(13.5)

%

 

 

 

 

$

212,356 

 

$

215,728 

 

$

(3,372)

 

(1.6)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy Costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel for power generation

 

41,717 

 

 

36,486 

 

 

5,231 

 

14.3 

%

 

 

 

Purchased power

 

39,902 

 

 

35,585 

 

 

4,317 

 

12.1 

%

 

 

 

Gas purchased for resale

 

37,620 

 

 

31,617 

 

 

6,003 

 

19.0 

%

 

 

 

Deferral of energy - electric - net

 

(19,335)

 

 

(12,670)

 

 

(6,665)

 

52.6 

%

 

 

 

Deferral of energy - gas - net

 

(14,375)

 

 

(1,240)

 

 

(13,135)

 

1,059.3 

%

 

 

Energy efficiency program costs

 

1,878 

 

 

 3,651 

 

 

(1,773)

 

(48.6)

%

 

 

 

              Total Costs

$

87,407 

 

$

93,429 

 

$

(6,022)

 

(6.4)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost by Segment:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric

$

64,162 

 

$

63,052 

 

 

1,110 

 

1.8 

%

 

 

 

Gas

 

23,245 

 

 

30,377 

 

 

(7,132)

 

(23.5)

%

 

 

 

 

$

87,407 

 

$

93,429 

 

$

(6,022)

 

(6.4)

%

 

 

Gross Margin by Segment:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric

$

108,465 

 

$

106,754 

 

$

1,711 

 

1.6 

%

 

 

 

Gas

 

16,484 

 

 

15,545 

 

 

939 

 

6.0 

%

 

 

 

$

124,949 

 

$

122,299 

 

$

2,650 

 

2.2 

%

 

Electric gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012.  Approximately $1.2 million of the increase is due to customer growth and approximately $1.1 million of the increase is due to an increase in customer usage primarily due to an increase in HDDs as shown in the tables below. 

Gas gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012.  The increase is primarily due to the increase in HDDs as shown in the tables below.

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period.  A degree day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F.  For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1.  In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.

The following table shows the HDDs and CDDs within SPPC’s service territory:

46


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

 

2012 

 

 

Variance

 

% Change

 

SPPC

 

 

 

 

 

 

 

 

 

 

 

 

 

Heating

 

2,285 

 

 

2,128 

 

 

157 

 

7.4 

%

 

 

Cooling

 

 - 

 

 

 - 

 

 

N/A

 

N/A

 

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

Electric Operating Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues:

2013 

 

2012 

 

 

Variance

 

% Change

 

 

Residential

$

62,978 

 

$

61,360 

 

$

1,618 

 

2.6 

%

 

 

Commercial

 

56,886 

 

 

58,712 

 

 

(1,826)

 

(3.1)

%

 

 

Industrial

 

34,640 

 

 

33,070 

 

 

1,570 

 

4.7 

%

 

 

 

Retail  revenues

 

154,504 

 

 

153,142 

 

 

1,362 

 

0.9 

%

 

 

Other

 

18,123 

 

 

16,664 

 

 

1,459 

 

8.8 

%

 

 

 

Total Operating Revenues

$

172,627 

 

$

169,806 

 

$

2,821 

 

1.7 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retail sales in thousands of MWhs

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

629 

 

 

600 

 

 

29 

 

4.8 

%

 

 

Commercial

 

650 

 

 

659 

 

 

(9)

 

(1.4)

%

 

 

Industrial

 

668 

 

 

633 

 

 

35 

 

5.5 

%

 

Retail sales in thousands of MWhs

 

1,947 

 

 

1,892 

 

 

55 

 

2.9 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average retail revenue per MWh

$

79.35 

 

$

80.94 

 

$

(1.59)

 

(2.0)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retail revenue increased for the three months ended March 31, 2013, as compared to the same period in 2012, primarily due to a $2.2 million increase in residential customer usage primarily due to an increase in HDDs as outlined in the table above, a $1.2 million increase in usage by mining customers and $0.7 million attributable to customer growth. These increases were partially offset by $1.8 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013 (see Note 3, Regulatory Actions of the Notes to Financial Statements) and $1.6 million of rate decreases due to various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements).

For the three months ended March 31, 2013, the average number of residential, commercial and industrial customers increased 0.6%, 0.7% and 4.8%, respectively, compared to the same period in 2012.

Electric operating revenues – Other increased by $1.5 million for the three months ended March 31, 2013, compared to the same period in 2012,primarily due to an increase in energy sales to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K).

Gas Operating Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

Gas Operating Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

$

22,545 

 

$

26,557 

 

$

(4,012)

 

(15.1)

%

 

 

Commercial

 

8,719 

 

 

10,966 

 

 

(2,247)

 

(20.5)

%

 

 

Industrial

 

2,278 

 

 

2,715 

 

 

(437)

 

(16.1)

%

 

 

 

Retail  Revenues

 

33,542 

 

 

40,238 

 

 

(6,696)

 

(16.6)

%

 

 

Wholesale Revenues

 

5,325 

 

 

4,830 

 

 

495 

 

10.2 

%

 

 

Miscellaneous

 

862 

 

 

854 

 

 

 

0.9 

%

 

 

 

Total Gas Revenues

$

39,729 

 

$

45,922 

 

$

(6,193)

 

(13.5)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retail sales in thousands of Dths

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

4,136 

 

 

3,708 

 

 

428 

 

11.5 

%

 

 

Commercial

 

2,076 

 

 

1,879 

 

 

197 

 

10.5 

%

 

 

Industrial

 

533 

 

 

476 

 

 

57 

 

12.0 

%

 

Retail sales in thousands of Dths

 

6,745 

 

 

6,063 

 

 

682 

 

11.2 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average retail revenue per Dth

$

4.97 

 

$

6.64 

 

$

(1.67)

 

(25.1)

%

47


SPPC’s retail gas revenues decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $9.7 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012, and various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K). The decrease was partially offset by a $2.7 million increase in customer usage primarily due to an increase in HDDs, as shown in the table above.

 Wholesale revenues increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to an increase in natural gas prices. 

Energy Costs

Energy Costs include purchased power and fuel for generation.  These costs are dependent upon many factors which may vary by season or period.  As a result, SPPC’s usage and average cost per MWh of purchased power versus fuel for generation can vary significantly as the company meets the demands of the season.  These factors include, but are not limited to:

weather

plant outages

total system demand

resource constraints

transmission constraints

gas transportation constraints

natural gas constraints

long-term contracts

mandated power purchases

generation efficiency; and

volatility of commodity prices

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

Energy Costs

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel for power generation

$

41,717 

 

$

36,486 

 

$

5,231 

 

14.3 

%

 

 

Purchased power

 

39,902 

 

 

35,585 

 

 

4,317 

 

12.1 

%

 

Total Energy Costs

$

81,619 

 

$

72,071 

 

$

9,548 

 

13.2 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

MWhs

 

 

 

 

 

 

 

 

 

 

 

 

 

   MWhs Generated (in thousands)

 

1,147 

 

 

1,178 

 

 

(31)

 

(2.6)

%

 

 

   Purchased Power (in thousands)

 

1,105 

 

 

1,011 

 

 

94 

 

9.3 

%

 

Total MWhs

 

2,252 

 

 

2,189 

 

 

63 

 

2.9 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average cost per MWh

 

 

 

 

 

 

 

 

 

 

 

 

 

   Average fuel cost per MWh of Generated Power

$

36.37 

 

$

30.97 

 

$

5.40 

 

17.4 

%

 

 

   Average cost per MWh of Purchased Power

$

36.11 

 

$

35.20 

 

$

0.91 

 

2.6 

%

 

 

   Average total cost per MWh

$

36.24 

 

$

32.92 

 

$

3.32 

 

10.1 

%

Energy Costs and the average total cost per MWh increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to higher natural gas prices.Total MWhs increased for the three month period primarily due to an increase in HDDs.

Fuel for generation costs increased for the three months ended March 31, 2013, compared to the same period in 2012.  Approximately $6.4 million of the change is due to higher natural gas prices partially offset by a decrease in volume of approximately $1.2 million.

Purchased power costs for the three months ended March 31, 2013, compared to the same period in 2012. Approximately $3.1 million of the increase is due to increased reliance on purchased power along with a $1.2 million increase due to higher natural gas prices.  Volume increased due to less reliance on internal generation.

Gas Purchased for Resale

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas purchased for resale

$

37,620 

 

$

31,617 

 

$

6,003 

 

19.0 

%

 

 

Gas purchased for resale (in thousands of Dths)

 

8,427 

 

 

8,274 

 

 

153 

 

1.8 

%

 

 

Average cost per Dth

$

4.46 

 

$

3.82 

 

$

0.64 

 

16.8 

%

48


Gas purchased for resale increased for the three months ended March 31, 2013,compared to the same period in 2012.  Approximately $5.3 million of the increase is due to higher natural gas prices and approximately $0.7 million is due to an increase in volume. 

Deferred Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferral of energy - electric - net

$

(19,335)

 

$

(12,670)

 

$

 (6,665) 

 

52.6 

%

 

 

Deferral of energy - gas - net

 

(14,375)

 

 

(1,240)

 

 

 (13,135) 

 

1,059.3 

%

 

 

 

$

(33,710)

 

$

(13,910)

 

$

 (19,800) 

 

142.3 

%

Deferred energy-electric for the three months ended March 31, 2013 include amortization of $(11.3) million which represent cash refunds to our customers for previous over-collections.  Further contributing to the 2013 deferred energy balance are under-collections of amounts recoverable in rates of $(8.0) million. 

Deferred energy-electric for the three months ended March 31, 2012 include amortization of previous over-collections of $(25.5) million, partially offset by over-collections of amounts recoverable in rates of $12.8 million. 

Deferred energy-gas for the three months ended March 31, 2013 include amortizations of previous over-collections of ($13.4) million and under-collections of amounts recoverable in rates of $(0.9) million.

Deferred energy-gas for the three months ended March 31, 2012 include amortization of previous over-collections of ($13.4) million, partially offset by over-collections of amounts recoverable in rates of $12.2 million.

Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates.  To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs.  Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs.  Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred.  Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Other Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy efficiency program costs

$

1,878 

 

$

3,651 

 

 

(1,773)

 

(48.6)

%

 

 

Other operating expenses

$

35,805 

 

$

36,432 

 

 

(627)

 

(1.7)

%

 

 

Maintenance

$

6,831 

 

$

9,453 

 

 

(2,622)

 

(27.7)

%

 

 

Depreciation and amortization

$

27,341 

 

$

25,872 

 

 

1,469 

 

5.7 

%

For the three months ended March 31, 2013, energy efficiency program costs decreased compared to the same period in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013.  Reference Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortization rate filings.

Other operating expensesdecreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to $1.0 million in lower telecommunications and software costs, and $0.6 million in lower pension and benefit costs. The decrease was partially offset by a $1.2 million increase in stock compensation costs.

Maintenance expense decreased for the threemonths ended March 31, 2013, compared to the same period in 2012, primarily due to a $1.4 million planned major outage at the Tracy Generating Station in 2012 and maintenance at the Valmy Generating Station in 2012 for $0.7 million.

Depreciation and amortization increased slightlyfor the three months ended March 31, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service.

49


Interest Expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

Interest expense

 

 

 

 

 

 

 

 

 

 

 

 

 

(net of AFUDC-debt: $294 and $416)

$

15,525 

 

$

16,973 

 

 

(1,448)

 

(8.5)

%

Interest expense decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to decreased debt amortization expense of $1.5 million. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding long-term debt.

Other Income (Expense)

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2012 

 

 

Variance

 

% Change

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense on regulatory items

$

(25)

 

$

(186)

 

 

161 

 

(86.6)

%

 

 

AFUDC-equity

$

523 

 

$

519 

 

 

 

0.8 

%

 

 

Other income

$

1,140 

 

$

2,183 

 

 

(1,043)

 

(47.8)

%

 

 

Other expense

$

(1,248)

 

$

(1,335)

 

 

87 

 

(6.5)

%

Interest expense on regulatory items decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $0.6 milliondecrease in interest on deferred energy as a result of lower over-collected balances in 2013, offset by a $0.4 million decrease in carrying charges on solar conservation programs. See Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further details of deferred energy balances.

AFUDC-equity did not change materially for the three months ended March 31, 2013, compared to the same period in 2012. 

Other income decreased for the three months ended March 31, 2013, compared to same period in 2012, primarily due to the $1.1 million settlement with CAISO in 2011, recognized in 2012. See Note 3, Regulatory Actions, FERC Matters, in the Notes to Financial Statements in the 2012 Form 10-K.

Other expense is comparable for the three months ended March 31, 2013, as compared to the same period in 2012.

Analysis of Cash Flows

SPPC’s cash flows increased during the three months ended March 31, 2013, compared to the same period in 2012, due to an increase in cash from operating activities and a decrease in cash used by investing and financing activities.

Cash from Operating Activities - The increase in cash from operating activities was primarily due to reduced coal and gas purchases, over collections of EEPR and reduction in refunds to customers for previously over collected BTER balances.  Also contributing to the increase was the receipt of approximately $9.0 million in insurance proceeds related to a previous claim.  These increases were partially offset by an under collection of energy costs in 2013, as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates. 

Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to decreased capital expenditure for the NV Energize project, partially offset by the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, also related to the NV Energize project.

Cash used by Financing Activities - The decrease in cash used by financing activities is primarily due to a reduction in dividends to NVE.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness.  Another significant use of cash is the refunding of previously over-collected amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.  Available liquidity as of March 31, 2013 was as follows (in millions):

Available Liquidity as of March 31, 2013 (in millions)

SPPC

Cash and Cash Equivalents

$

85.3 

Balance available on Revolving Credit Facility(1)

243.7 

$

329.0 

(1)

As of May 7, 2013, SPPC had approximately $243.7 million available under its revolving credit facility which includes reductions for letters of credits.

50


SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, SPPC may use its revolving credit facility in order to meet its liquidity needs.  Alternatively, depending on the usage of the revolving credit facility, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. 

SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013.  To meet this maturing debt obligation, SPPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt.  As of May 8, 2013, SPPC has no borrowings on its revolving credit facility, not including letters of credit. In 2012, SPPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below).  In 2012, SPPC did not experience any limitations in the credit markets, nor do we expect any significant limitations in 2013.  However, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

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

However, if energy costs rise at a rapid rate, or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less.  In order to maintain sufficient liquidity under such circumstances, SPPC may be required to delay capital expenditures, refinance debt, or receive capital contributions from NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities.  As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.  Additionally, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

During the three months ended March 31, 2013, SPPC did not pay dividends to NVE.On May 8, 2013 SPPC declared a dividend to NVE of $20.0 million.

SPPC designs operating and capital budgets to control operating costs and capital expenditures.  In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, environmental compliance, improvement, and maintenance of facilities.

During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in SPPC’s 2012 Form 10-K.

Factors Affecting Liquidity

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt.  As of March 31, 2013, the most restrictive of the factors below is the PUCN authority.  Based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million.  However, depending on NVE’s or NPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting SPPC’s ability to issue debt are further detailed below:

a.

Financing authority from the PUCN - As of March 31, 2013, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority (1) to issue additional long-term debt securities of up to $350million; (2) to refinance up to approximately $598.3 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million;

b.

Financial covenants within SPPC’s financing agreements – Under the SPPC Credit Agreement, the Utility must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.00.  Based on March 31, 2013 financial statements, SPPC was in compliance with this covenant and could incur up to $1.1 billion of additional indebtedness;

All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently rated investment grade.  However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants; and

c.

Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.2 billion.

51


   Ability to Issue General and Refunding Mortgage Securities

To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its and NVE’s financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the SPPC Indenture.

The SPPC Indenture creates a lien on substantially all of SPPC’s properties in Nevada.  As of March 31, 2013, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $824 millionof additional General and Refunding Mortgage Securities as of March 31, 2013.  That amount is determined on the basis of:

1.

70% of net utility property additions; and/or

2.

the principal amount of retired General and Refunding Mortgage Securities.

Property additions include plant in service.  Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.

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

Credit Ratings

The liquidity of SPPC, the cost and availability of borrowing by SPPC under the SPPC Credit Agreement, the potential exposure of SPPC to collateral calls under various contracts, and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for SPPC’s debt.  On April 30, 2013, Fitch upgraded SPPC’s corporate credit rating from BB+ to investment grade BBB-.  SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P.  The senior secured debt credit ratings are as follows:

Rating Agency

Fitch(1)

Moody’s(2)

S&P(3)

SPPC

Sr. Secured Debt

     BBB+*

      Baa1*

     BBB+*

*Investment grade

(1)

Fitch’s lowest level of “investment grade” credit rating is BBB-.

(2)

Moody’s lowest level of “investment grade” credit rating is Baa3.

(3)

S&P’s lowest level of “investment grade” credit rating is BBB-.

Fitch’s, Moody’s and S&P’s rating outlooksare stable for SPPC.  

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

Energy Supplier Matters

With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP.  The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change, which includes a credit rating downgrade in SPPC may allow the counterparty to request adequate financial assurance, which if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  A default must be declared within 30 days of the event, giving rise to the default becoming known.  A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received.  The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time.  According to the net mark-to-market value as of March 31, 2013, no amounts would be due to or from SPPC for all suppliers continuing to provide power under a WSPP agreement.  These contracts qualify for the normal purchases and normal sales scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet. 

52


Gas Supplier Matters

With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.  Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery.  At the present time, no counterparties require payment in advance of delivery. 

Gas transmission service is secured under FERC tariffs or custom agreements.  These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved tariffs, which under certain circumstances require the Utilities to provide collateral to continue receiving service.

Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Financial Statements in the 2012 Form 10-K,  SPPC’s Financing Transactions, the availability under the SPPC’s revolving credit facility is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the credit facility.  Currently, there are no negative mark-to-market exposures that would impact borrowings of SPPC.  If deemed prudent, SPPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

Cross Default Provisions

None of the financing agreements of SPPC contains a crossdefault provision that would result in an event of default by SPPC upon an event of default by NVE or NPC under any of its financing agreements.  In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due.  Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.

RECENT PRONOUNCEMENTS

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

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of March 31, 2013, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity.  Such instruments are fixed and variable rate debt.  Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands):

 

 

 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

Expected Maturities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair

 

 

 

 

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

Thereafter

 

Total

 

 

Value

Long-Term Debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NVE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Rate

$

 - 

 

$

 195,000 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

315,000 

 

$

510,000 

 

$

575,444 

 

 

Average Interest Rate

 

 - 

 

 

 2.81 

%

 

 - 

 

 

 - 

 

 

 - 

 

 

6.25 

%

 

4.93 

%

 

 - 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Rate

$

 - 

 

$

 125,000 

 

$

 250,000 

 

$

210,000 

 

$

 - 

 

$

2,545,000 

 

$

3,130,000 

 

$

3,873,718 

 

 

Average Interest Rate

 

 - 

 

 

 7.38 

%

 

5.88 

%

 

5.95 

%

 

 - 

 

 

6.47 

%

 

6.42 

%

 

 - 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable Rate

$

 98,100 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

75,675 

 

$

173,775 

 

$

170,737 

 

 

Average Interest Rate

 

 0.61 

%

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

0.56 

%

 

0.59 

%

 

 - 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SPPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Rate

$

 250,000 

 

$

 - 

 

$

 - 

 

$

 450,000 

 

$

 - 

 

$

251,742 

 

$

951,742 

 

$

1,115,492 

 

 

Average Interest Rate

 

 5.45 

%

 

 - 

 

 

 - 

 

 

 6.00 

%

 

 - 

 

 

6.75 

%

 

6.05 

%

 

 - 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable Rate

$

 - 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

 214,675 

 

$

214,675 

 

$

184,895 

 

 

Average Interest Rate

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

0.56 

%

 

0.56 

%

 

 - 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TOTAL DEBT

$

 348,100 

 

$

320,000 

 

$

250,000 

 

$

660,000 

 

$

 - 

 

$

3,402,092 

 

$

4,980,192 

 

$

5,920,286 

53


Commodity Price Risk

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

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties.  Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition.  The Utilities’ credit risk associated with trading counterparties was approximately $98.6 million as of March 31, 2013, which compares to balances of $77.5 million at December 31, 2012. The increase from December 31, 2012 is primarily due to the increase in forward prices of power and natural gas during the first quarter of 2013.

ITEM 4.CONTROLS AND PROCEDURES 

(a)Evaluation of disclosure controls and procedures. 

NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’Company's disclosure controls and procedures (as defined in RulesRule 13a-15(e) and 15d-15(e) ofpromulgated under the Securities and Exchange Act of 1934) have1934, 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 as of March 31, 2013, the registrants’Company's disclosure controls and procedures were effective.

(b)Change in internal controls over financial reporting.

There were no changeseffective to ensure that information required to be disclosed by the Company in the registrants’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 controlscontrol over financial reporting induring the first quarter of 2013ended March 31, 2014 that havehas materially affected, or areis reasonably likely to materially affect, the registrants’Company's internal controlscontrol over financial reporting.

54



18



PART II  -  OTHER INFORMATION


ITEM 1.                      LEGAL PROCEEDINGS
Item 1.
Legal Proceedings

None.

Other Legal Matters

NVE and its subsidiaries, through
Item 1A.
Risk Factors


There has been no material change to the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had, or in the opinion of management, is expected to have a significant impact on their financial positions or results of operations.  See Note 7, Commitments and Contingencies, of the Condensed Notes to Financial Statements for further discussion of other legal matters.

ITEM 1A.RISK FACTORS

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

As of the dateCompany's Annual Report on Form 10-K for the year ended December 31, 2013.


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

Not applicable.

Item 3.
Defaults Upon Senior Securities

Not applicable.

Item 4.
Mine Safety Disclosures

None.

Item 5.
Other Information

Not applicable.

Item 6.
Exhibits

The exhibits listed on the accompanying Exhibit Index are filed as part of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2012 Form 10-K.

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

Issuer Purchases of Equity Securities

The following table contains information about NVE’s purchases of common stock for the quarter ended March 31, 2013:

Quarterly Report.

 

 

 

 

 

 

 

 

 

 

Total Number of Shares

 

 

Maximum Number of

 

 

 

 

 

 

 

 

 

 

Purchased as Part of

 

 

Shares that may yet be

 

 

 

 

Total Number of

 

Average Price

 

 

Publicly Announced

 

 

Purchased Under the

Period

 

 

Shares Purchased (1)

 

Paid Per Share

 

 

Plans or Programs

 

 

Plans or Programs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1 - January 31, 2013

 

 

 197,178 

 

$

18.49 

 

 

N/A

 

 

N/A

February 1 - February 28, 2013

 

 

 - 

 

 

 - 

 

 

N/A

 

 

N/A

March 1 - March 31, 2013

 

 

 - 

 

 

 - 

 

 

N/A

 

 

N/A

 

Total

 

 

197,178 

 

$

18.49 

 

 

 - 

 

 

 - 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

Represents shares of common stock purchased on the open market to provide shares to participants under various NVE stock compensation plans. These purchases were not made pursuant to a publicly announced stock repurchase plan or program.


ITEM 3.DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.OTHER INFORMATION

None. 


55

19

ITEM 6.EXHIBITS

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

(10)    NV Energy, Inc.:

10.1

Form of Performance Shares Agreement for 2013 Awards.

10.2

Form of Restricted Stock Unit Agreement for 2013 Awards.

(12)    NV Energy, Inc.:

12.1

Statement regarding computation of Ratios of Earnings to Fixed Charges.

          Nevada Power Company:

12.2

Statement regarding computation of Ratios of Earnings to Fixed Charges.

          Sierra Pacific Power Company:

12.3

Statement regarding computation of Ratios of Earnings to Fixed Charges.

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

31.1

Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

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

31.3

Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4

Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.5

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

31.6

Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

32.1

Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

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

32.3

Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4

Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.5

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

32.6

Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Schema

101.CAL

XBRL Calculation Linkbase

101.LAB

XBRL Label Linkbase

101.PRE

XBRL Presentation Linkbase

101.DEF

XBRL Definition Linkbase

56




SIGNATURES


SIGNATURES

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


NV Energy, Inc.

             (Registrant)

NEVADA POWER COMPANY

(Registrant)

Date:May 8, 2013

By:

/s/ Jonathan S. Halkyard

Jonathan S. Halkyard

Chief Financial Officer

(Principal Financial Officer)

Date: May 8, 2013

2, 2014

By:

/s/ E. Kevin Bethel

E. Kevin Bethel

Chief Accounting Officer

(Principal Accounting Officer)

Nevada Power Company d/b/a NV Energy

             (Registrant)

Date:  May 8, 2013

By:

/s/ Jonathan S. Halkyard

Jonathan S. Halkyard

Senior Vice President and Chief Financial Officer

(principal financial and accounting officer)



20



EXHIBIT INDEX

Exhibit No.

Description

(

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)

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

32.1

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

Date:  May 8, 2013

32.2

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

By:

/s/ E. Kevin Bethel

101

E. Kevin Bethel

Chief Accounting Officer

(Principal Accounting Officer)

Sierra PacificThe following financial information from Nevada Power Company d/b/a NV Energy

             (Registrant)

Date:  May 8, 2013

By:

/s/ Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014Jonathan S. Halkyard

Jonathan S. Halkyard

Chief, 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 Officer

(Principal Financial Officer)

Date: Statements, tagged in summary and detail.May 8, 2013

By:

/s/ E. Kevin Bethel

E. Kevin Bethel

Chief Accounting Officer

(Principal Accounting Officer)



57

21