10-K 1 form10-k2.htm NVE 2012 FORM 10-K  

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF

 THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

I.R.S. Employer

 

State of

Commission File

 

Registrant, Address of Principal Executive Offices and Telephone

 

Identification No.

 

Incorporation

 

 

 

 

 

 

 

1-08788

 

NV ENERGY, INC.

 

88-0198358

 

Nevada

 

 

6226 West Sahara Avenue

 

 

 

 

 

 

Las Vegas, Nevada  89146

 

 

 

 

 

 

(702) 402-5000

 

 

 

 

 

 

2-28348

 

NEVADA POWER COMPANY d/b/a NV ENERGY

 

88-0420104

 

Nevada

 

 

6226 West Sahara Avenue

 

 

 

 

 

 

Las Vegas, Nevada 89146

 

 

 

 

 

 

(702) 402-5000

 

 

 

 

 

 

0-00508

 

SIERRA PACIFIC POWER COMPANY d/b/a NV ENERGY

 

88-0044418

 

Nevada

 

 

P.O. Box 10100 (6100 Neil Road )

 

 

 

 

 

 

Reno, Nevada 89520-0024 (89511)

 

 

 

 

 

 

(775) 834-4011

 

 

 

 

 

(Title of each class)

 

(Name of exchange on which registered)

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

 

 

Securities of NV Energy, Inc.:

 

 

Common Stock, $1.00 par value

 

New York Stock Exchange

 

 

 

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

 

 

Securities of Nevada Power Company:

 

 

Common Stock, $1.00 stated value

 

 

Securities of Sierra Pacific Power Company:

 

 

Common Stock, $3.75 par value

 

 

    

 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

NV Energy, Inc.  Yesþ Noo  Nevada Power Company Yeso Noþ  Sierra Pacific Power Company Yeso  Noþ 

     Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso   Noþ 

     Indicate by check mark whether each of the registrants (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   No 

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

     Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 

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

NV Energy, Inc.:  Large accelerated filer þ  Accelerated filer o  Non-accelerated filer  o   Smaller reporting company o  

Nevada Power Company:  Large accelerated filer  o  Accelerated filer  o  Non-accelerated filer þ   Smaller reporting company 

Sierra Pacific Power Company: Large accelerated filer o  Accelerated filer o Non-accelerated filer þ  Smaller reporting company 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso  Noþ (Response applicable to all registrants)

State the aggregate market value of NV Energy, Inc.'s common stock held by non-affiliates. As of June 30, 2012: $4,148,875,605

Indicate the number of shares outstanding of each of the registrant’s classes of Common Stock, as of the latest practicable date.

Common Stock, $1.00 par value, of NV Energy, Inc. outstanding at February 21, 2013: 234,916,220 Shares 

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding 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 par value, of Sierra Pacific Power Company.

DOCUMENTS INCORPORATED BY REFERENCE:

     Portions of NV Energy, Inc.'s definitive proxy statement to be filed in connection with the annual meeting of shareholders, to be held May 8, 2013, are incorporated by reference into Part III hereof.

     This combined Annual Report on Form 10-K 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.

 

 


 

 

 

NV ENERGY, INC.

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

2012 ANNUAL REPORT ON FORM 10-K

CONTENTS

 

 

Page

 

 

Acronyms & Terms

5

 

 

 

 

 

PART I

 

 

 

 

 

 

ITEM 1.

Business  

7

ITEM 1A.

Risk Factors

33

ITEM 1B.

Unresolved Staff Comments

38

ITEM 2.

Properties

38

ITEM 3.

Legal Proceedings

39

ITEM 4.

Mine Safety Disclosures

39

 

 

 

 

 

PART II

 

 

 

 

 

 

ITEM 5.

 

Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (NVE)

40

ITEM 6.

Selected Financial Data

42

ITEM 7.

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

44

 

 

Executive Overview

47

 

 

NV Energy, Inc.

 

 

 

 

Results of Operations

56

 

 

 

Analysis of Cash Flows

56

 

 

 

Liquidity and Capital Resources (NVE Consolidated)

57

 

 

Nevada Power Company

 

 

 

 

Results of Operations

63

 

 

 

Analysis of Cash Flows

70

 

 

 

Liquidity and Capital Resources

71

 

 

Sierra Pacific Power Company

 

 

 

 

Results of Operations

76

 

 

 

Analysis of Cash Flows

84

 

 

 

Liquidity and Capital Resources

84

ITEM 7A.

Quantitative and Qualitative Disclosures About Market Risk

90

ITEM 8.

Financial Statements and Supplementary Data

91

 

 

Reports of Independent Registered Public Accounting Firm

93

 

 

NV Energy, Inc.

 

 

 

 

Consolidated Statements of Comprehensive Income

96

 

 

 

Consolidated Balance Sheet

97

 

 

 

Consolidated Statements of Cash Flows

99

 

 

 

Consolidated Statements of Shareholders’ Equity

100

 

 

Nevada Power Company

 

 

 

 

Consolidated Statements of Comprehensive Income

101

 

 

 

Consolidated Balance Sheet

102

 

 

 

Consolidated Statements of Cash Flows

104

 

 

 

Consolidated Statements of Shareholder’s Equity

105

 

 

Sierra Pacific Power Company

 

 

 

 

Consolidated Statements of Comprehensive Income

106

 

 

 

Consolidated Balance Sheet

107

 

 

 

Consolidated Statements of Cash Flows

109

 

 

 

Consolidated Statements of Shareholder’s Equity

110

           

 

 

3

 


 

 

 

 

 

 

Notes to Financial Statements

 

 

 

 

Note 1.  Summary of Significant Accounting policies

111

 

 

 

Note 2.  Segment Information

117

 

 

 

Note 3.  Regulatory Actions

120

 

 

 

Note 4.  Investments in Subsidiaries & Other Property

130

 

 

 

Note 5.  Jointly Owned Facilities

130

 

 

 

Note 6.  Long-Term Debt

132

 

 

 

Note 7.  Fair Value of Financial Instruments

136

 

 

 

Note 8.  Debt Covenant and Other Restrictions

136

 

 

 

Note 9.  Income Taxes (Benefits)

139

 

 

 

Note 10.  Retirement Plan and Postretirement Benefits

142

 

 

 

Note 11.  Stock Compensation Plans

148

 

 

 

Note 12.  Commitments and Contingencies

152

 

 

 

Note 13.  Common Stock and Other Paid-In Capital

157

 

 

 

Note 14.  Earnings Per Share (NVE)

159

 

 

 

Note 15.  Assets Held For Sale

159

 

 

 

Note 16.  Quarterly Financial Data (Unaudited)

160

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

161

ITEM 9A.

Controls and Procedures

162

ITEM 9B.

Other Information

164

 

 

 

 

 

PART III

 

 

 

 

 

 

ITEM 10.

Directors, Executive Officers and Corporate Governance of the Registrant

164

ITEM 11.

Executive Compensation

165

ITEM 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

165

ITEM 13.

Certain Relationships and Related Transactions, and Director Independence

165

ITEM 14.

Principal Accounting Fees and Services

165

 

 

 

 

 

PART IV

 

 

 

 

 

 

ITEM 15.

Exhibits, Financial Statement Schedules

166

 

 

 

 

Signatures

167

 

4

 


 

 

 

ACRONYMS AND TERMS

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

 

 

 

Acronym/Term

 

Meaning

 

 

 

2012 Form 10-K

 

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

2013 Proxy Statement

 

NVE’s, NPC’s and SPPC’s Proxy Statement for 2013

AFUDC-debt

 

Allowance for borrowed funds used during construction

AFUDC-equity

 

Allowance for equity funds used during construction

BOD

 

Board of Directors

BTER

 

Base Tariff Energy Rate

BTGR

 

Base Tariff General Rate

CAISO

 

California Independent System Operator Corporation

California Assets

 

SPPC’s California electric distribution and generation assets

CalPeco

 

California Pacific Electric Company

CALPX

 

California Power Exchange

CDD

 

Cooling degree days

CDWR

 

California Department of Water Resources

CEO

 

Chief Executive Officer of NV Energy, Inc.

CIAC

 

Contributions in Aid of Construction

Clark Generating Station

 

550 MW nominally rated William Clark Generating Station

Clark Peaking Units

 

600 MW nominally rated peaking units at the William Clark Generating Station

CPA

 

Certified Public Accountant

CPUC

 

California Public Utilities Commission

CSIP

 

Common Stock Investment Plan

CWIP

 

Construction Work-In-Progress

d/b/a

 

Doing business as

DEAA

 

Deferred Energy Accounting Adjustment

DOE

 

Department of Energy

DOS

 

Distribution Only Service

DSM

 

Demand Side Management

Dth

 

Decatherm

EEC

 

Ely Energy Center

EEIR

 

Energy Efficiency Implementation Rate

EEPR

 

Energy Efficiency Program Rate

EPA

 

United States Environmental Protection Agency

EPS

 

Earnings Per Share

EROC

 

Enterprise Risk Oversight Committee

ESP

 

Energy Supply Plan

ESPP

 

Employee Stock Purchase Plan

EWAM

 

Enterprise, Work & Asset Management

FASB

 

Financial Accounting Standards Board

FASC

 

FASB Accounting Standards Codification

FERC

 

Federal Energy Regulatory Commission

Fitch

 

Fitch Ratings, Ltd.

Ft. Churchill Generating Station

 

226 megawatt nominally rated Fort Churchill Generating Station

GAAP

 

Accounting Principles Generally Accepted in the United States

GBT

 

Great Basin Transmission, LLC

GBT South

 

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

Goodsprings

 

7.5 MW nominally rated Goodsprings Recovered Energy Generating Station

GPSF-B

 

Global Project & Structured Finance Corporation

GRC

 

General Rate Case

Harry Allen Generating Station

 

142 MW nominally rated Harry Allen Generating Station, expanded in 2011 to 642 total MWs

HDD

 

Heating degree days

Higgins Generating Station

 

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

IBEW

 

International Brotherhood of Electrical Workers

Independence Lake

 

2,325 acres of forestland in the Sierra Nevada Mountains purchased from NV Energy, Inc. by The Nature Conservancy

IRP

 

Integrated Resource Plan

IRS

 

Internal Revenue Service

kV

 

Kilovolt

kWh

 

Kilowatt Hour

LDC

 

Local Distributing Company

Legislature

 

Nevada State Legislature

Lenzie Generating Station

 

1,102 MW nominally rated Chuck Lenzie Generating Station

LIBOR

 

London Interbank Offered Rate

LTIP

 

Long-Term Incentive Plan

MMBtu

 

Million British Thermal Units

Mohave Generating Station

 

1,580 MW nominally rated Mohave Generating Station

Moody’s

 

Moody’s Investors Services, Inc.

MW

 

Megawatt

MWh

 

Megawatt hour

NAAQS

 

National Ambient Air Quality Standards

Navajo Generating Station

 

255 MW nominally rated Navajo Generating Station

5

 


 

 

 

 

NDEP

 

Nevada Division of Environmental Protection

NEDSP

 

Non-Employee Director Stock Plan

NEICO

 

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

NPC’s 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

 

NVE project which includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management.

NWPP

 

Northwest Power Pool

ON Line

 

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

Peabody

 

Peabody Western Coal Company

PEC

 

Portfolio Energy Credit

Piñon Pine

 

Piñon Pine Coal Gasification Demonstration Project

Portfolio Standard

 

Nevada Renewable Energy Portfolio Standard

PPC

 

Piñon Pine Corporation

PPIC

 

Piñon Pine Investment Company

PUCN

 

Public Utilities Commission of Nevada

Reid Gardner Generating Station

 

325 MW nominally rated Reid Gardner Generating Station

REPR

 

Renewable Energy Program Rate

RFP

 

Request for Proposal

ROE

 

Return on Equity

ROR

 

Rate of Return

S&P

 

Standard & Poor’s

Salt River

 

Salt River Project

SEC

 

United States Securities and Exchange Commission

Silverhawk Generating Station

 

395 MW nominally rated Silverhawk Generating Station

Smart Meters

 

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

SNWA

 

Southern Nevada Water Authority

SPCOM

 

Sierra Pacific Communications

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

SPPC’s 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

SRSG

 

Southwest Reserve Sharing Group

Term Loan

 

$195 million loan agreement entered into on October 7, 2011 between NVE and JP Morgan Chase Bank, N.A.,

 

 

as Administrative agent for the lenders a party thereto

TMWA

 

Truckee Meadows Water Authority 

Tracy Generating Station

 

541 MW nominally rated Frank A. Tracy Generating Station

TRED

 

Temporary Renewable Energy Development

TSR

 

Total Shareholder Return

TUA

 

Transmission Use Agreement

U.S.

 

United States of America

Utilities

 

Nevada Power Company and Sierra Pacific Power Company

Valmy Generating Station

 

261 MW nominally rated Valmy Generating Station

VIE

 

Variable Interest Entity

WSPP

 

Western Systems Power Pool 

6

 


 

 

 

FORWARD LOOKING STATEMENTS

 

The discussion of forward looking statements in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, is incorporated herein by reference.

 

PART I

 

ITEM 1.  BUSINESS

 

NV Energy, Inc. is an investor-owned holding company that was incorporated under Nevada law on December 12, 1983.  The company’s stock is traded on the New York Stock Exchange under the symbol “NVE”.  NVE’s mailing address is P.O. Box 98910 (6226 West Sahara Avenue), Las Vegas, Nevada 89151.

 

NVE has four primary, wholly-owned subsidiaries: Nevada Power Company d/b/a NV Energy, Sierra Pacific Power Company d/b/a NV Energy, NVE Insurance Company, Inc. and Lands of Sierra.  References to NVE refer to the consolidated entity, except where the context provides otherwise.  NPC and SPPC are referred to collectively in this report as the “Utilities”. 

 

The Utilities operate three business segments, as defined by the Segment Reporting Topic of the FASC: NPC electric; SPPC electric; and SPPC natural gas.  Electric service is provided by NPC to Las Vegas and surrounding Clark County, and by SPPC to northern Nevada.  Natural gas service is provided by SPPC in the Reno-Sparks area of Nevada.  The Utilities are the major contributors to NVE’s financial position and results of operations.  Other subsidiaries either do not meet the definition of a segment or are below the quantitative threshold for separate segment disclosure and are combined under “all other” in the following pages.  Parenthetical references are included after each major section title to identify the specific entity or entities addressed in the section.  See Note 2, Segment Information, of the Notes to Financial Statements, for further discussion.

 

NPC is a Nevada corporation organized in 1929 and, by itself and through a predecessor corporation, has been providing electric services to southern Nevada since 1906.  NPC became a subsidiary of NVE in July 1999.  Its mailing address is P.O. Box 98910 (6226 West Sahara Avenue), Las Vegas, Nevada 89151.

 

NEICO is a wholly-owned subsidiary of NPC.  NEICO is a 25% member of Northwind Aladdin, LLC, the other 75% of Northwind Aladdin, LLC is owned by Macquarie Infrastructure Company Trust.

 

A Nevada corporation since 1965, SPPC was originally incorporated in Maine in 1912.  SPPC became a subsidiary of NVE in 1984.  Its mailing address is P.O. Box 10100 (6100 Neil Road), Reno, Nevada 89520-0024.

 

SPPC has three primary, wholly-owned subsidiaries: GPSF-B, PPC and PPIC.  GPSF-B, PPC and PPIC, collectively, own Piñon Pine Company, LLC, which was formed to utilize federal income tax credits available under Section 20 of the Internal Revenue Code associated with the alternative fuel (syngas) produced by the coal gasifier located at the Piñon Pine facility.

 

Periodic reports for NVE, NPC and SPPC on Form 10-K and Form 10-Q and current reports on Form 8-K are made available to the public, free of charge, on NVE’s website (www.nvenergy.com) through links on this website to the SEC’s website at www.sec.gov, as soon as reasonably practicable after they have been filed with the SEC.  The contents of the above referenced website address are not part of this Form 10-K.  The public may also read any copy of materials filed with the SEC by NVE, NPC or SPPC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549.  Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-(800) SEC-0030.  Reports, proxy and information statements, and other information regarding NVE, NPC and SPPC may also be obtained directly from the SEC’s website, www.sec.gov.  Available on the nvenergy.com website are the code of ethics for the chief executive officer, chief financial officer and controller, charters for the Audit, Compensation, Finance, and Nominating and Governance Committees of NVE’s BOD and our corporate governance and standards of conduct guidelines.  Printed copies of these documents may be obtained free of charge by writing to NVE’s Corporate Secretary at NV Energy, Inc., 6226 West Sahara Avenue, Las Vegas, Nevada 89146.

 

The statistical data used throughout this 2012 Form 10-K, other than data relating specifically solely to NVE and its subsidiaries,  are based upon independent industry publications, government publications, reports by market research firms or other published independent sources.  We 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 we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information.  

 

7

 


 

 

 

Overview

 

NPC and SPPC are public utilities that generate, transmit and distribute electric energy in Nevada and, in the case of SPPC, also deliver natural gas service.  At year-end 2012, NVE served approximately 1.2 million electric customers, of which approximately 850,000 electric customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas were served by NPC, and approximately 324,000 electric customers in an approximate 42,000 square mile area of western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko were served by SPPC.  Additionally, SPPC provided natural gas service to approximately 153,000 customers in an area of about 800 square miles in Nevada’s Reno/Sparks area. 

 

Major industries served by the Utilities include gaming/recreation, mining, warehousing/manufacturing and governmental entities.  The Utilities’ revenues and operating income are subject to fluctuations during the year due to the impacts that seasonal weather, rate changes and customer usage patterns have on demand for electric energy and services.  NPC is a summer peaking utility, experiencing its highest retail energy sales in response to the demand for air conditioning.  SPPC’s electric system peak also occurs in the summer, with a slightly lower peak demand in the winter.  SPPC’s gas business typically peaks in the winter months due to heating demands.

 

NPC and SPPC service territories are as follows:

 

Service Area Update 2-10-11.jpg 

 

 

NVE Transformation

 

Beginning in 2006, NVE committed to an energy strategy to manage resources in relation to 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 effort 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 PUCN 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 investment for our shareholders. 

 

As discussed above, in 2006, the Utilities embarked on their energy strategy to manage resources in relation to their load.  Since then the energy strategy has transformed to include: empowering customers through focused service and efficiency programs,

8

 


 

 

 

pursuing cost-effective renewable energy initiatives, optimizing generating facilities and enhancing transmission capabilities, and engaging employees to improve processes, reduce costs and enhance performance.  The details of this energy strategy are discussed below:

 

Energy Strategy

 

Empower customers through focused service and efficiency programs

 

                NV Energize

 

NV Energize is a NVE project which 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 December 31, 2012, NVE has installed approximately 1.3 million Smart Meters in Nevada, and the implementation of the NV Energize project is nearing completion.  NVE expects to substantially complete the installation process of the final 80,000 meters before the end of the second quarter of 2013.

 

The NV Energize system provides more convenience for customers and is achieving operating savings through both automated meter reading and the elimination to date of approximately one 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. 

 

Pursue cost-effective renewable energy initiatives

 

Even before Nevada first adopted the Portfolio Standard in 1997, NVE has been committed to renewable energy.  As part of our continued commitment, NVE will seek the most competitive opportunities that will benefit our customers, our companies, our state, and our environment.  NVE has a number of tools available to undertake renewable energy initiatives, including construction of new renewable energy facilities, entering into new renewable energy contracts, exploring opportunities to either jointly construct or develop renewable energy projects, investment in renewable energy projects, undertaking short-term purchases from existing renewable facilities and restructuring existing renewable relationships for the benefit of our customers.

 

NVE has been required by statute to comply with the Portfolio Standard since 1997, when Nevada first mandated that a certain percentage of the energy that the Utilities deliver come from renewable energy resources (including solar energy) and efficiency measures.  In 2013, the Utilities are required to obtain an amount of PECs equivalent to 18% of their total retail energy from renewable energy resources, with up to 25% of this amount eligible to be met with energy efficiency measures and at least 5% required to be met with solar energy resources.  The Portfolio Standard increases every two to five years until it reaches 25% in 2025.  NVE is committed to meeting the Portfolio Standard using the most cost-effective means for our customers and undertaking those renewable energy opportunities that present the greatest value for our companies and our customers.

 

Optimizing generating facilities and enhancing  transmission capabilities

 

Since 2006, when NVE began its energy independence initiative, we have added over 3,800 MWs (nominally rated) of internal generation.  As a result, NVE may obtain approximately 80% of its energy from internal generation.  In 2013, NVE’s management continues to strive to optimize the Utilities’ energy portfolio in order to meet load obligations in a cost effective and reliable manner.  In addition, to the extent the Utilities have the economic opportunity to sell excess capacity or energy, they may enter into such transactions to reduce overall energy costs.  NVE anticipates it will have sufficient resources to meet its forecasted load requirements for 2013.  However, resource adequacy could be affected by a number of factors, including the unplanned retirement of generating stations, plant outages, the timing of commercial operation of renewable energy projects and associated purchase power agreements, customer behavior with respect to energy efficiency and conservation programs, and environmental regulations which may limit our ability to operate certain generating units. 

 

Construction of ON Line

 

NVE will continue with the construction of ON Line which will enable us to optimize our generation assets by enhancing our transmission capabilities.  Upon completion (expected in late 2013), ON Line will connect NVE’s southern and northern service territories and, pending certain state and federal regulatory approvals, will provide the ability to jointly dispatch energy throughout the

9

 


 

 

 

state and provide access to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to manage its Portfolio Standard, discussed above, and optimize its generating facilities.  ON Line will also provide 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 by mid-2013.

 

ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South.  The Joint Project consists of two phases.  In Phase 1 of the Joint Project, the parties would complete construction of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  The Utilities own a 25% interest in ON Line and have entered into a TUA with GBT-South for its 75% interest in ON Line. The Utilities’ 25% interest in ON Line, which approximates $138 million (excluding AFUDC), will be allocated 95% and 5% to NPC and SPPC, respectively.  See the Transmission  section, later, for further details of ON Line.  Also, see the Integrated Resource Plan section, later, for further discussion of certain regulatory matters concerning ON Line.

 

Engage employees to improve processes, reduce costs, and enhance performance

 

The Utilities will continue to control operating and maintenance and capital costs through diligent review and process improvement initiatives by providing appropriate tools to our employees to find ways to reduce costs, improve processes, and enhance performance.  This is particularly important at a time when customer growth is low.  Going forward this will continue to be an over-arching theme of our energy strategy. Our goal is to reduce or eliminate upward pressure on our customers’ prices while always delivering safe and reliable energy and assure compliance with all laws and regulations.

 

Business and Competitive Environment        

                 

   Operations                        

                                                                   

      NPC and SPPC Electric

 

The Utilities are charged with meeting the energy needs for most of Nevada.  Revenues are impacted by rate changes, cost of fuel and purchased power, seasonal or atypical weather and customer use.  The Utilities’ electric peak demand occurs in the summer.  Therefore, the Utilities’ revenues and associated expenses are not incurred or generated evenly throughout the year.

 

                To serve their customer base, the Utilities generate electricity and purchase power in accordance with an ESP, as discussed in more detail later in this section, under Energy Supply

 

       SPPC Gas    

 

The Gas LDC is responsible for providing natural gas to residential, commercial and industrial customers.  SPPC is well connected with several major gas producing regions and gas transportation systems into northern Nevada.  SPPC’s gas distribution system receives gas supplies from two interstate natural gas pipelines, the Paiute Pipeline Company and the Tuscarora Gas Transmission Company.  In addition, SPPC has contracted for natural gas storage services to supplement firm and spot market purchases.

 

      Regulatory Environment

 

The FERC and PUCN regulate portions of the Utilities’ accounting practices and electricity and natural gas rates.  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 buy transportation for natural gas.  The PUCN has authority over rates charged to retail customers, the issuance of securities by the Utilities and transactions with affiliated parties.

 

                Nevada state regulations require the Utilities to file electric GRCs every three years with the PUCN to adjust rates, based primarily on cost of service and return on investment.  Nevada state regulations also require the Utilities to file annual DEAA applications to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent rate change.  The Utilities may also file to reset BTERs quarterly, based on the last 12 months fuel and purchased power costs.  Additionally, Nevada regulations allow an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest.  Moreover, in 2010, the PUCN adopted regulations authorizing an electric utility to recover an amount from its customers that is attributable to the measurable and verifiable effects associated with the Utilities’ implementation of energy efficiency and

10

 


 

 

 

conservation programs approved by the PUCN.  In addition, the regulation approved the transition of the recovery of energy efficiency program costs from general rates (filed every three years) to recover through independent annual rate filings.  The Utilities also file an triennial IRP, as discussed later. See Note 3, Regulatory Actions, of the Notes to Financial Statements, for further discussion on the various rate cases.

 

The PUCN regulations also require a Gas Supply Report as well as a Gas Informational Report to be filed annually.  SPPC may also file gas GRCs to adjust gas division rates including cost of service and return on investment.  Rate cases are discussed in more detail in Note 3 Regulatory Actions, of the Notes to Financial Statements.

 

   Competition

 

      NPC and SPPC Electric

 

The Utilities operate under certificates of public convenience and necessity as regulated by the PUCN, as well as, franchise agreements with local governments in their respective operating areas.  Under Nevada state law, commercial customers with an average annual load of one MW or more may file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider.  The law requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards.  In particular, departing customers must secure new energy resources that are not under contract to NPC or SPPC, the departure must not burden the Utilities with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances.  The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or to the Utilities.  Customers wishing to choose a new supplier must provide 180-day notice to NPC or SPPC.  The Utilities would continue to provide transmission, distribution, metering, and billing services to such customers.  

 

Currently, there are no material applications pending with the PUCN to exit the system in NPC’s or SPPC’s service territory. 

 

Commercial customers who receive approval from the PUCN to acquire electric energy, capacity, and ancillary services from another provider, and who may have previously received service from the Utilities, may migrate to being served under the provisions of a DOS agreement.  Under a DOS agreement, customer-specific facilities charges will continue to be collected along with a flat distribution charge per meter.  Currently, NPC and SPPC have 50 and three premises served, respectively, under the DOS tariff.

 

Distributed generation remains a relatively limited source of competition for the Utilities.  However, changes in law, technological improvements and differences in regulatory oversight for distributed generation providers may result in increased competition for the Utilities in the future. 

 

   SPPC Gas

 

SPPC’s natural gas LDC business is subject to competition from other suppliers and other forms of energy available to its customers.  Large gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the Incentive Natural Gas Rate tariff.  Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose their source of fuel.  Additionally, customers using greater than 1,000 therms per day have the ability to secure their own gas supplies under the Transportation Tariff.  As of January 1, 2013, there were 17 large customers securing their own supplies.  These customers have a combined firm distribution load of approximately 5,739 Dth per day.  Transportation customers continue to pay firm and interruptible distribution charges.  These customers are responsible for procuring and paying for their own gas supply, which reduces SPPC’s purchases, but does not have an impact on net income.

11

 


 

 

 

 

Sales

 

                In 2012, NVE’s revenues, NPC’s revenues and SPPC’s electric revenues were approximately $3.0 billion, $2.1 billion and $725.9 million, respectively.  SPPC’s natural gas business revenues were approximately $108 million in 2012 or 13% of SPPC’s total revenues.  In 2012, NVE’s, NPC’s and SPPC’s electric system peaks were 7,437 MW, 5,761 MW and 1,676 MW, respectively, compared to 7,052 MW, 5,539 MW and 1,513 MW, respectively, in 2011. 

 

                NVE’s electric customers by class contributed the following MWh sales:

 

 

 

 

 

MWh Sales

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

MWh

 

% of Total

 

MWh

 

% of Total

 

MWh

 

% of Total

 

 

Retail sales in thousands of MWhs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 11,382 

 

37.9 %

 

 10,754 

 

37.0 %

 

 11,149 

 

38.5 %

 

 

 

Commercial

 7,430 

 

24.7 %

 

 7,205 

 

24.8 %

 

 7,357 

 

25.4 %

 

 

 

Industrial

 10,373 

 

34.5 %

 

 10,218 

 

35.2 %

 

 10,217 

 

35.3 %

 

 

Retail sales in thousands of MWhs

 29,185 

 

97.1 %

 

 28,177 

 

97.0 %

 

 28,723 

 

99.2 %

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wholesale

 622 

 

2.1 %

 

 631 

 

2.2 %

 

 13 

 

 - %

 

 

Sales to Public Authorities

 232 

 

0.8 %

 

 241 

 

0.8 %

 

 248 

 

0.8 %

 

 

Total

 30,039 

 

100.0 %

 

 29,049 

 

100.0 %

 

 28,984 

 

100.0 %

 

 

NPC’s electric customers by class contributed the following MWh sales:

 

 

 

 

 

MWh Sales

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

MWh

 

% of Total

 

MWh

 

% of Total

 

MWh

 

% of Total

 

 

Retail sales in thousands of MWhs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 9,098 

 

42.4 %

 

 8,523 

 

41.1 %

 

 8,684 

 

41.6 %

 

 

 

Commercial

 4,500 

 

20.9 %

 

 4,353 

 

21.0 %

 

 4,340 

 

20.8 %

 

 

 

Industrial

 7,666 

 

35.7 %

 

 7,653 

 

36.9 %

 

 7,618 

 

36.5 %

 

 

Retail sales in thousands of MWhs

 21,264 

 

99.0 %

 

 20,529 

 

98.9 %

 

 20,642 

 

98.9 %

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to Public Authorities

 217 

 

1.0 %

 

 225 

 

1.1 %

 

 232 

 

1.1 %

 

 

Total

 21,481 

 

100.0 %

 

 20,754 

 

100.0 %

 

 20,874 

 

100.0 %

 

 

Total retail MWh sales increased approximately 3.6% in 2012 from 2011, primarily due to an increase in customer usage as a result of an increase in CDDs, as outlined in the tables below, particularly during the second quarter of 2012, as well as increased usage by certain industrial customers and slight growth in the number of customers. NPC’s average residential and commercial customers increased by 1.4% and 0.7%, respectively, while average industrial customers decreased by 1.5%.

 

SPPC’s electric customers by class contributed the following MWh sales:

 

 

 

 

 

MWh Sales

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

MWh

 

% of Total

 

MWh

 

% of Total

 

MWh

 

% of Total

 

 

Retail sales in thousands of MWhs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 2,284 

 

26.7 %

 

 2,231 

 

26.9 %

 

 2,465 

 

30.4 %

 

 

 

Commercial

 2,930 

 

34.2 %

 

 2,852 

 

34.4 %

 

 3,017 

 

37.2 %

 

 

 

Industrial

 2,707 

 

31.6 %

 

 2,565 

 

30.9 %

 

 2,599 

 

32.0 %

 

 

Retail sales in thousands of MWhs

 7,921 

 

92.5 %

 

 7,648 

 

92.2 %

 

 8,081 

 

99.6 %

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wholesale

 622 

 

7.3 %

 

 631 

 

7.6 %

 

 13 

 

0.2 %

 

 

Sales to Public Authorities

 15 

 

0.2 %

 

 16 

 

0.2 %

 

 16 

 

0.2 %

 

 

Total

 8,558 

 

100.0 %

 

 8,295 

 

100.0 %

 

 8,110 

 

100.0 %

 

 

12

 


 

 

 

Total retail MWh sales increased approximately 3.6% in 2012 from 2011, due to increased customer usage primarily due to an increase in CDDs as outlined in the table below and increased usage by mining customers.  SPPC’s average number of residential and industrial customers increased by 0.7% and 4.7%, respectively, and commercial customers remained flat.  SPPC’s total retail electric MWh sales decreased in 2011, as compared to 2010, primarily due to the sale of the California Assets to CalPeco in January 2011 and the sale of energy to CalPeco accounted for as a wholesale customer beginning in 2011.

 

    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 degrees Fahrenheit.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65 degrees Fahrenheit.  CDDs measure cooling energy demand and indicate how far the temperature averaged above 65 degrees Fahrenheit.  For example, if a location had a mean temperature of 60 degrees Fahrenheit on day 1 and 80 degrees Fahrenheit 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 heating degree days and cooling degree days within NPC’s and SPPC’s service territories for each of the last three years:

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

 

 

Change From

 

 

 

Change From

 

 

 

 

 

 

 

Amount

 

 Prior Year

 

Amount

 

Prior Year

 

Amount

 

 

NPC

 

 

 

 

 

 

 

 

 

 

 

 

 

HDD

 

 1,659 

 

(18.7)%

 

 2,040 

 

7.7 %

 

 1,895 

 

 

 

CDD

 

 4,032 

 

13.9 %

 

 3,540 

 

(3.0)%

 

 3,648 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SPPC

 

 

 

 

 

 

 

 

 

 

 

 

 

HDD

 

 4,352 

 

(14.9)%

 

 5,112 

 

5.0 %

 

 4,868 

 

 

 

CDD

 

 1,272 

 

32.0 %

 

 964 

 

4.6 %

 

 922 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Data Source:  National Weather Service

 

 

 

 

 

 

 

 

 

 

Demand

 

   Load and Resources Forecast

 

NPC’s peak electric demand increased in 2012 to 5,761 MWs from 5,539 MWs in 2011.  SPPC’s peak electric demand increased in 2012 to 1,676 MWs from 1,513 MWs in 2011.  Variations in energy usage occur as a result of varying weather conditions, economic conditions, and other energy usage behaviors, such as conservation efforts by our customers.  These variations necessitate a continual balancing of loads and resources and requires both purchases and sales of energy under short and long-term contracts as well as the prudent management and optimization of available resources.

 

The Utilities plan to meet their customers’ needs through a combination of company-owned-generation and purchased power.  See the Generation section and Purchased Power section below for details of the Utilities’ generation assets and contracts for purchased power.  Remaining needs will be met through power purchases through term RFPs or short-term purchases.  As shown in the tables below, the Utilities have sufficient resources to meet anticipated customer requirements.  However, resource adequacy may be affected by a variety of factors including, but not limited to, the unplanned retirement of generating stations, the timing or achievement of commercial operation with respect to renewable energy power projects not yet commercially operable, the intermittent generation of renewable energy resources, customer behavior with respect to energy efficiency, and conservation programs and environmental regulations which may limit our ability to operate certain generating units.  Resource adequacy provides the Utilities the ability to maintain a reliable supply of energy; however as discussed under the Resource Optimization section, to the extent the resources are not needed, the Utilities will attempt to sell their additional availability in an effort to reduce costs.  

 

Below are tables as of December 31, 2012 summarizing the forecasted summer electric capacity requirement and resource needs of NVE and the Utilities after consideration of energy conservation programs and the completion of ON Line (as discussed in the Transmission section later):

13

 


 

 

 

 

NVE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forecasted Electric Capacity Requirements and Resources (MW)

 

 

 

 

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

 

 

 

 

 

 

 

 

 

 

 

Total requirements(1)

 

 8,129 

 

 8,191 

 

 8,296 

 

 8,347 

 

 8,468 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Resources:

 

 

 

 

 

 

 

 

 

 

 

 

Company-owned  generation(2)

 

 6,078 

 

 6,078 

 

 5,942 

 

 6,164 

 

 6,164 

 

 

Contracts for power purchases

 

 2,172 

 

 1,829 

 

 1,837 

 

 1,615 

 

 1,615 

 

 

Contracts for renewable energy power purchases, not

 

 

 

 

 

 

 

 

 

 

 

 

yet commercially operable(3)

 

 10 

 

 226 

 

 233 

 

 233 

 

 240 

 

Total resources

 

 8,260 

 

 8,133 

 

 8,012 

 

 8,012 

 

 8,019 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total additional required (additional resources)(4)

 

 (131) 

 

 58 

 

 284 

 

 335 

 

 449 

 

(1)

Includes projected system peak load plus 12% planning reserves.

(2)

Includes 232 MWs of peaking capacity at Reid Gardner Generating Station Unit No. 4, which is co-owned with CDWR, see Item 2, Properties.  The increase in 2016 company-owned generation is based on the assumption that the purchase option with respect to the Sunpeak units will be exercised.  Currently MWs associated with the Sun Peak units are included in power purchases.  The decrease in company-owned generation is due to the retirement of Tracy Units 1 and 2, expected as of January 1, 2015.

(3)

Includes long term purchase power agreements for renewable energy that are not yet commercially operable and/or may not materialize due to project delays, under performance, or cancelations.

(4)

Total additional required is the difference between the total requirements and total resources.  Total additional required represents the amount needed to achieve the total requirement; conversely, additional resources represents resources in excess of the total requirement.

 

NPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forecasted Electric Capacity Requirements and Resources (MW)

 

 

 

 

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

 

 

 

 

 

 

 

 

 

 

 

Total requirements(1)

 

 6,306 

 

 6,281 

 

 6,332 

 

 6,415 

 

 6,500 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Resources:

 

 

 

 

 

 

 

 

 

 

 

 

Company-owned  generation(2)

 

 4,570 

 

 4,570 

 

 4,570 

 

 4,792 

 

 4,792 

 

 

Contracts for power purchases

 

 1,751 

 

 1,511 

 

 1,511 

 

 1,289 

 

 1,289 

 

 

Contracts for renewable energy power purchases, not

 

 

 

 

 

 

 

 

 

 

 

 

yet commercially operable(3)

 

 10 

 

 226 

 

 233 

 

 233 

 

 240 

 

Total resources

 

 6,331 

 

 6,307 

 

 6,314 

 

 6,314 

 

 6,321 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total additional required (additional resources)(4)

 

 (25) 

 

 (26) 

 

 18 

 

 101 

 

 179 

 

(1)

Includes projected system peak load plus 12% planning reserves.

(2)

Includes 232 MWs of peaking capacity at Reid Gardner Generating Station Unit No. 4, which is co-owned with CDWR, see Item 2, Properties.  The increase in 2016 company-owned generation is based on the assumption that the purchase option with respect to the Sunpeak units will be exercised.  Currently MWs associated with the Sun Peak units are included in power purchases. 

(3)

Includes long term purchase power agreements for renewable energy that are not yet commercially operable and/or may not materialize due to project delays, under performance, or cancelations.

(4)

Total additional required is the difference between the total requirements and total resources.  Total additional required represents the amount needed to achieve the total requirement; conversely, additional resources represents resources in excess of the total requirement..

14

 


 

 

 

 

SPPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forecasted Electric Capacity Requirements and Resources (MW)

 

 

 

 

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

 

 

 

 

 

 

 

 

 

 

 

Total requirements(1)

 

 1,823 

 

 1,910 

 

 1,964 

 

 1,932 

 

 1,968 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Resources:

 

 

 

 

 

 

 

 

 

 

 

 

Company-owned generation(2)

 

 1,508 

 

 1,508 

 

 1,372 

 

 1,372 

 

 1,372 

 

 

Contracts for power purchases

 

 421 

 

 318 

 

 326 

 

 326 

 

 326 

 

Total resources

 

 1,929 

 

 1,826 

 

 1,698 

 

 1,698 

 

 1,698 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total additional required (additional resources)(3)

 

 (106) 

 

 84 

 

 266 

 

 234 

 

 270 

 

(1)

Includes projected system peak load plus 15% planning reserves.

(2)

The decrease in company-owned generation is due to the retirement of Tracy Units 1 and 2, expected as of January 1, 2015.

(3)

Total additional  required represents the difference between the total requirements and total resources.  Total additional required represents the amount   needed to achieve the total requirement; conversely, additional resources represents resources in excess of the total requirement.

 

    Resource Optimization

 

                Resource optimization entails the prudent dispatch of company generation, as well as the purchase and sale of electric power, fuel and financial energy products by the Utilities.  The Utilities optimize their portfolios continuously in order to meet load obligations in a cost effective and reliable manner within transmission constraints.  The Utilities continuously monitor the resources available to meet load obligations, recognizing the uncertainty not only in system conditions, such as planned and unplanned outages of generating or transmission facilities, but also in regional energy markets organized across different commodities, locations, demand and trading timeframes.  As conditions change and new information becomes available, the Utilities optimize their portfolios as appropriate to account for changes in load, cost, volatility, reliability and other commercial or technical factors. 

 

Energy Supply

 

   Total System

 

The Utilities manage a portfolio of energy supply options.  The availability of alternate resources allows the Utilities to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity.  During 2012, NVE generated 68.6% of its total system requirements, purchasing the remaining 31.4%, NPC generated approximately 74.0% of its total system requirements, purchasing the remaining 26.0%, and SPPC generated 55.3% of its total electric energy requirements, purchasing the remaining 44.7% as shown below.

 

NVE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

MWh

 

% of Total

 

MWh

 

% of Total

 

MWh

 

% of Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Generation

 

 18,433,398 

 

58.7 %

 

 14,942,167 

 

49.1 %

 

 15,373,818 

 

50.5 %

 

Coal Generation

 

 3,083,752 

 

9.8 %

 

 4,545,627 

 

14.9 %

 

 5,152,214 

 

17.0 %

 

 

Total Generated

 

 21,517,150 

 

68.6 %

 

 19,487,794 

 

64.0 %

 

 20,526,032 

 

67.5 %

 

 

Total Purchased

 

 9,860,686 

 

31.4 %

 

 10,945,375 

 

36.0 %

 

 9,860,562 

 

32.5 %

 

 

Total System

 

 31,377,836 

 

100.0 %

 

 30,433,169 

 

100.0 %

 

 30,386,594 

 

100.0 %

 

NPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

MWh

 

% of Total

 

MWh

 

% of Total

 

MWh

 

% of Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Generation

 

 14,436,037 

 

64.7 %

 

 11,687,714 

 

54.1 %

 

 11,666,152 

 

53.6 %

 

Coal Generation

 

 2,058,842 

 

9.3 %

 

 3,346,506 

 

15.5 %

 

 3,739,339 

 

17.2 %

 

 

Total Generated

 

 16,494,879 

 

74.0 %

 

 15,034,220 

 

69.6 %

 

 15,405,491 

 

70.8 %

 

 

Total Purchased

 

 5,805,805 

 

26.0 %

 

 6,577,339 

 

30.4 %

 

 6,350,795 

 

29.2 %

 

 

Total System

 

 22,300,684 

 

100.0 %

 

 21,611,559 

 

100.0 %

 

 21,756,286 

 

100.0 %

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SPPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

MWh

 

% of Total

 

MWh

 

% of Total

 

MWh

 

% of Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Generation

 

 3,997,361 

 

44.0 %

 

 3,254,453 

 

36.9 %

 

 3,707,666 

 

43.0 %

 

Coal Generation

 

 1,024,910 

 

11.3 %

 

 1,199,121 

 

13.6 %

 

 1,412,875 

 

16.3 %

 

 

Total Generated

 

 5,022,271 

 

55.3 %

 

 4,453,574 

 

50.5 %

 

 5,120,541 

 

59.3 %

 

 

Total Purchased

 

 4,054,881 

 

44.7 %

 

 4,368,036 

 

49.5 %

 

 3,509,767 

 

40.7 %

 

 

Total System

 

 9,077,152 

 

100.0 %

 

 8,821,610 

 

100.0 %

 

 8,630,308 

 

100.0 %

 

As a supplement to their own generation, the Utilities purchase spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements.  Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies.  The Utilities decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits.  Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods.  Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than the Utilities own generation, again, subject to net system import limits.  

 

NPC’s 2012 company generated MWhs increased 9.7% from 2011 resulting in a corresponding decrease in purchase power.  SPPC’s 2012 company generated MWhs also increased 12.8% resulting in a decrease in purchase power compared to 2011.    See Energy Supply, above,    for additional information regarding the Utilities’ purchasing strategies.

 

   Generation

 

NPC’s generation capacity consists of a combination of 44 gas, oil and coal generating units with a combined summer capacity of 4,570 MWs as described in Item 2, Properties.  In 2012, NPC generated approximately 74.0% of its total system requirements. 

 

SPPC’s generation capacity consists of a combination of 17 gas, oil and coal generating units with a combined summer capacity of 1,508 MWs as described in Item 2, Properties.  In 2012, SPPC generated approximately 55.3% of its total system requirements.

 

   Fuel Sources

 

The Utilities’ 2012 fuel sources for electric generation were primarily provided by natural gas and coal.  The average costs of gas and coal, including hedging costs, for energy generation per MMBtu for the years 2008 through 2012, along with the percentage contribution to the Utilities’ total fuel sources were as follows:

 

 

NPC Electric

 

 

Average Consumption Cost & Percentage Contribution to Total Fuel Cost

 

 

 

 

 

Gas

 

Coal

 

 

 

 

 

$/MMBtu

 

Percent

 

$/MMBtu

 

Percent

 

 

 

2012 

 

3.18 

 

83.5 %

 

2.43 

 

16.5 %

 

 

 

2011 

 

4.66 

 

71.3 %

 

2.32 

 

28.7 %

 

 

 

2010 

 

5.73 

 

68.5 %

 

2.21 

 

31.5 %

 

 

 

2009 

 

5.09 

 

71.8 %

 

2.23 

 

28.2 %

 

 

 

2008 

 

7.79 

 

66.5 %

 

2.17 

 

33.5 %

 

 

For a discussion of the change in fuel costs, see Results of Operations in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

NPC has two long term coal supply contracts for the Reid Gardner Generating Station with Arch Coal Sales Company, a subsidiary of Arch Coal, Inc. (“Arch”) that extend through December 31, 2013. Coal shipped under these contracts is supplied from Arch’s mine in Central Utah. These contracts represent 73% of the current forecasted coal requirements of Reid Gardner Generating Station for 2013. However, as of December 31, 2012, NPC’s Reid Gardner Generating Station coal inventory level was 357,915 tons, or approximately 97 days of consumption at full capacity.

 

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A take or pay transportation services contract with the Union Pacific Railroad Company that extends through 2014 provides for unit train coal deliveries from various mines in Utah, Colorado and Wyoming as well as from the Provo, Utah interchange to the Reid Gardner Generating Station in Moapa, Nevada.

 

The Navajo Generating Station is jointly owned by NPC along with five other entities and is operated by Salt River Project. Coal is obtained under a Coal Sales Agreement with Peabody Western Coal Company that extends through 2019. Coal is supplied from the Kayenta Mine’s surface mining operations conducted on Navajo Nation and Hopi Tribe reservation lands on the Black Mesa in Arizona.

 

In 2012, NPC used a four season ahead physical gas laddering strategy to cover the time period beginning with summer season 2012.  NPC employs two seasonal competitive bidding processes each year.  Therefore, the physical gas prices are set at an appropriate industry index during the month of current delivery.  Natural gas is delivered to NPC through the use of firm gas transport contracts.  Monthly and daily gas supply adjustments are made based on the current energy marketplace and operational considerations.

 

The laddering strategy entails the purchase of one quarter of NPC’s gas supply approximately two years before delivery, another quarter about 18 months before delivery, another quarter about 12 months before delivery and the last quarter procured about 6 months before delivery, or one season ahead.  NPC utilizes this strategy in an attempt to ensure that all required gas supply for a season is not procured at one point in time, a point in time that may be subject to supply constraints and/or high premiums.

 

To secure gas supplies for the generating stations that NPC either owns or has under long-term contract (tolling arrangements), NPC contracted for firm winter, summer, and annual gas supplies with numerous domestic suppliers.  In 2012, for generating stations located in NPC’s control area, gas supply net purchases averaged approximately 317,645 Dth per day, with the winter period contracts averaging approximately 256,704 Dth per day, and the summer period contracts averaging approximately 360,645 Dth per day.

 

Listed below is NPC’s transportation portfolio as of December 31, 2012:

 

 

Firm Transportation Capacity

 

Dth per day firm

 

Term

 

 

 

Kern River

 

50,000 

 

Summer

 

 

 

Kern River

 

374,925 

 

Annual

 

 

 

Kern River (Backhaul)

 

134,000 

 

Annual

 

 

 

 

 

 

 

 

 

 

 

Southwest Gas

 

288,000 

 

Annual

 

 

Domestic gas supplies are accessed utilizing gas transport service from Kern River directly to Lenzie, Silverhawk, Higgins, Harry Allen, and Reid Gardner (for start-up only) Generating Stations or from Kern River to SWG and then to LV Cogen 1, LV Cogen 2, Clark, and Sunpeak Generating Stations.

 

 

SPPC Electric

 

 

Average Consumption Cost & Percentage Contribution to Total Fuel Cost

 

 

 

 

 

Gas

 

Coal

 

 

 

 

 

$/MMBtu

 

Percent

 

$/MMBtu

 

Percent

 

 

 

2012 

 

3.78 

 

75.4 %

 

3.14 

 

24.6 %

 

 

 

2011 

 

5.60 

 

66.5 %

 

2.73 

 

33.5 %

 

 

 

2010 

 

6.54 

 

66.4 %

 

2.32 

 

33.6 %

 

 

 

2009 

 

7.98 

 

63.5 %

 

2.12 

 

36.5 %

 

 

 

2008 

 

8.95 

 

57.6 %

 

2.09 

 

42.4 %

 

 

For a discussion of the change in fuel costs, see Results of Operations in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations

                 

SPPC has a long-term coal supply contract with Black Butte Coal Company for the Valmy Generating Station that extends through December 31, 2015. Coal shipped under this contract is supplied from Black Butte’s surface mine in Southern Wyoming.  This contract represents 98% of the current forecasted coal requirements of Valmy Generating Station for 2013, 132% for 2014, and 64% for 2015. However, as of December 31, 2012, SPPC’s coal inventory level at Valmy Generating Station was 395,061 tons or approximately 131 days of consumption at full capacity.

 

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A take or pay transportation services contract with Union Pacific Railroad Company that extends through 2014 provides for unit train coal deliveries from various mines in Utah, Colorado and Wyoming as well as from the Provo, Utah interchange to the Valmy Generating Station near Battle Mountain, Nevada.

 

In 2012, SPPC used a four season ahead physical gas laddering strategy, similar to NPC.  SPPC employs two seasonal competitive bidding processes each year.  Therefore, the physical gas prices are set at an appropriate industry index during the month of current delivery.  Natural gas is delivered to SPPC through the use of firm gas transport contracts.  Monthly and daily gas supply adjustments are made based on the current energy marketplace and operational considerations.

 

      SPPC Gas

 

SPPC plans its gas transportation and supply to serve a demand that would occur if the average of the high and low temperatures for a given day drops to negative five degrees Fahrenheit, which is estimated to be 192,840 Dth per day for the winter of 2012/2013.

 

To secure gas supplies for SPPC’s generating stations and the LDC, SPPC contracted for firm winter, summer, and annual gas supplies with numerous Canadian and domestic suppliers using a four season ahead physical gas laddering strategy discussed above.  In 2012, seasonal and monthly gas supply net purchases averaged approximately 125,134 Dth per day with the winter period contracts averaging approximately 144,986 Dth per day (November 2011- March 2012), and the summer period contracts averaging approximately 110,191 Dth per day (April – October 2012).

 

SPPC’s firm natural gas supply is supplemented with natural gas storage services and supplies from Northwest’s facility located at Jackson Prairie in southern Washington.  The Jackson Prairie facility can contribute up to a total of 12,687 Dth per day of peaking supplies.  In an effort to optimize the value of SPPC’s assets, from November 2011 through October 2012 and November 2012 through October 2013, SPPC entered into one year agreements whereby the respective counterparty acquired the rights to the Jackson Prairie storage facility and some of SPPC’s gas transport assets during the term of the agreement with SPPC retaining the ability to call on the resources, subject to limitations. 

 

SPPC also has storage on the Paiute Pipeline system.  This liquefied gas storage facility provides for an incremental supply of 23,000 Dth per day and is available at any time during the winter with two hours notice. Therefore, this storage project supports increases in short term gas supply needs due to unforeseen events such as extreme weather patterns and pipeline interruptions.

 

Listed below is SPPC’s transportation and storage portfolio as of December 31, 2012:

 

 

Firm Transportation Capacity

 

Dth per day firm

 

Term

 

 

Northwest

 

68,696 

 

Annual

 

 

Paiute

 

68,696 

 

Winter

 

 

Paiute

 

61,044 

 

Summer

 

 

Paiute

 

23,000 

 

Winter (Storage related)

 

 

AB Nova (Canadian Pipeline)

 

130,319 

 

Annual

 

 

BC System (Canadian Pipeline)

 

128,932 

 

Annual

 

 

GTN

 

140,169 

 

Winter

 

 

GTN

 

79,899 

 

Summer

 

 

Tuscarora

 

172,823 

 

Annual

 

 

 

 

 

 

 

 

 

Storage Capacity

 

 

 

 

 

 

Northwest

 

281,242 

 

Storage Capacity (Jackson Prairie)

 

 

 

 

12,687 

 

Daily Withdrawal Capacity

 

 

 

 

 

 

 

 

 

Paiute

 

303,604 

 

Storage Capacity

 

 

 

 

23,000 

 

Daily Withdrawal Capacity

 

 

Canadian gas supplies are accessed utilizing gas transport service on AB Nova to BC System to GTN to Tuscarora and then directly to Tracy Generating Station.  Domestic gas supplies are also accessed utilizing gas transport on Northwest to Paiute and then directly to Ft. Churchill and Tracy Generating Stations.  The LDC is dual sourced from the pipelines listed above.

 

Total LDC supply requirements in 2012 and 2011 were 14.6 million Dth and 16.7 million Dth, respectively.  SPPC’s electric generating fuel requirements for 2012 and 2011 were 31.2 million Dth and 25.9 million Dth, respectively.

 

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   Water Supply

 

      NPC and SPPC

 

Assured supplies of water are important for the Utilities’ generating plants, and at the present time, the Utilities have adequate water to meet their generation needs.  Reliable water supply is critical to the entire desert southwest region, including the State of Nevada.  The newer generation facilities in the Utilities’ fleet have been designed to minimize water usage and employ innovative conservation based technologies such as dry cooling and recycled water.  Although there are current drought conditions in the Las Vegas area, water resources for most of these facilities rely on regional aquifers and recycled water that are not closely connected to transient drought conditions. 

 

   Purchased Power

 

Under the guidelines set forth in the respective ESPs, NPC and SPPC continue to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation resources, with the objective of minimizing its net average system operating costs.  During 2012, NPC and SPPC purchased approximately 26.0% and 44.7%, respectively, of their total electric energy requirements.

 

       NPC Electric

                                   

NPC purchases both forward firm energy and spot market energy based on economics, regulatory requirements, operating reserve margins, and unit availability.  NPC seeks to manage its loads efficiently by utilizing its generation resources and long-term purchase power contracts in conjunction with buying and selling opportunities in the market.  

   

NPC has entered into long-term purchase power contracts (3 or more years) with suppliers that generate electricity utilizing gas and renewable resource facilities with a total nameplate capacity of approximately 2,401 MW and contract termination dates ranging from 2013 to 2038.  Included in these contracts are approximately 797 MW of nameplate capacity of renewable energy of which approximately 229 MW of nameplate capacity are under development or construction and not currently available.  The PECs from renewable resource facilities are used towards compliance with the Portfolio Standard.  Energy from some of these contracts is delivered and sold to SPPC through intercompany related purchase power contracts due to the resource location and transmission constraints; however, NPC retains the PECs associated with such contracts.  The completion of ON Line will give NPC the ability to take delivery of the energy from these contracts.

 

NPC is a member of the SRSG and the WSPP.  NPC’s membership in the SRSG has allowed it to network with other utilities in an effort to use its resources more efficiently in the sharing of responsibilities for reserves.  

 

NPC’s credit standing may affect the terms under which NPC is able to purchase fuel and electricity in the western energy markets; however, as a result of NPC’s investment grade credit rating over the last several years, this was not a significant factor in 2012.

 

      SPPC Electric

 

SPPC purchases both forward firm energy and spot market energy based on economics, regulatory requirements, operating reserve margins, and unit availability.  SPPC seeks to manage its loads efficiently by utilizing its generation resources and long-term purchase power contracts in conjunction with buying and selling opportunities in the market.  

 

SPPC has entered into long-term purchase power contracts (3 or more years) with suppliers that generate electricity utilizing coal and renewable resource facilities, with a total nameplate capacity of approximately 415 MW and contract termination dates ranging from 2016 to 2039.  Included in these contracts are approximately 212 MW of nameplate capacity of renewable energy.  The PECs from renewable resource facilities are used towards compliance with the Portfolio Standard.  Energy from one of these contracts is delivered and sold to NPC through an intercompany related purchase power contract due to the resource location and transmission constraints; however, SPPC retains the PECs associated with this contract.  The completion of ON Line will give SPPC the ability to take delivery of the energy from these contracts.

 

SPPC is a member of the NWPP and WSPP.  These pools have provided SPPC further access to reserves and spot market power, respectively, in the Pacific Northwest and Southwest.  In turn, SPPC’s generation resources provide a backup source for other pool members who rely heavily on hydroelectric systems.  

 

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SPPC’s credit standing may affect the terms under which SPPC is able to purchase fuel and electricity in the western energy markets; however, as a result of SPPC’s investment grade credit rating over the last several years, this was not a significant factor in 2012.

 

 Transmission 

 

    General 

 

                Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers.  Transmission systems are designed to move electricity over long distances because generators can be located anywhere from a few miles to hundreds of miles from customers.

 

The Utilities’ electric transmission systems are part of the Western Interconnection, the regional grid in the western United States.  The Western Interconnection includes the interconnected transmission systems of fourteen western states, two Canadian provinces and the parts of Mexico that make up the Western Electricity Coordinating Council (WECC).  WECC is one of eight regional councils of the NERC, the entity responsible for the reliability, adequacy and security of North America’s bulk electric system.

 

NPC’s transmission system links generating units within and outside of the NPC Balancing Authority Area for delivery to the NPC distribution system and provides interconnections with the balancing authority areas of Western Area Power Administration, Los Angeles Department of Water and Power, California Independent System Operator (“CAISO”), and PacifiCorp. 

  

SPPC’s transmission system links generating units within the SPPC balancing authority area for delivery to the SPPC distribution system and provides interconnections with the balancing authority areas of Idaho Power, Los Angeles Department of Water and Power, CAISO, PacifiCorp, and Bonneville Power Administration.  

 

The service territories of NPC and SPPC are not directly interconnected at present; however, the construction of ON Line, discussed below, is expected to be completed in late 2013 and will interconnect the systems for the first time. 

 

Under the NERC Standards, the Utilities are Balancing Authorities, Transmission Operators, and Transmission Owners among other roles.  As defined by NERC, the Balancing Authority integrates resource plans ahead of time, maintains load-interchange-generation balance within the Balancing Authority Area, and supports Interconnection frequency in real time (i.e., the Balancing Authority is responsible for assuring that the demands on the system are matched by an equivalent amount of resources, whether from generators within its area or from energy imports).  The Transmission Operator is responsible for the reliability of its local transmission system, and operates or directs the operations of the transmission facilities.  The Transmission Owner owns and maintains transmission facilities.  The Utilities also schedule power deliveries over their transmission systems and maintain reliability through their operations and maintenance practices and by verifying that customers are matching loads with resources.

 

The Utilities plan, build, and operate transmission systems that delivered approximately 21,481,000 MWh and 8,558,000 MWh of electricity to NPC’s and SPPC’s retail customers, respectively, in their Balancing Authority Areas in 2012.  The NPC system handled a system peak load of 5,761 MW in 2012 through approximately 1,725 miles of transmission lines and other transmission facilities ranging from 60 kV to 500 kV.  The SPPC system handled a system peak load of 1,676 MW in 2012 through 2,050 miles of transmission lines and other facilities ranging from 55 kV to 345 kV.  The Utilities process generation and transmission interconnection requests and requests for transmission service from a variety of customers.  These requests usually involve new planning studies and the negotiation of contracts with new and existing customers. 

 

   Transmission Regulatory Environment

 

Transmission for the Utilities’ bundled retail customers is subject to the jurisdiction of the PUCN for rate making purposes.  The Utilities provide cost based wholesale and retail access transmission services under the terms of a FERC approved Open Access Transmission Tariff (“OATT”).  In accordance with the OATT, the Utilities offer several services to eligible customers:

 

          Network transmission service (equivalent to the service NVE provides for NVE’s bundled retail customers)

          Long-term and short-term firm point-to-point transmission service (“highest quality” service with fixed delivery and receipt points)

          Non-firm point-to-point service (“as available” service with fixed delivery and receipt points)

          Generation interconnection

          Retail open access

 

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These services are all offered on a nondiscriminatory basis in that all potential customers, including the Utilities, have an equal opportunity to access the transmission system.  The Utilities’ transmission business is managed and operated independently from the energy marketing business in accordance with FERC’s Standards of Conduct.

 

On October 31, 2012, NVE filed separate Notices of Transmission Rate Changes with FERC for NPC and SPPC.  The filings requested incremental rate relief of approximately $14.5 million annually effective January 1, 2013. On December 31, 2012, FERC suspended the effective date of the rates until June 1, 2013 (except for two rates that were reductions from the existing rate which were effective January 1, 2013) and set the cases for hearing or settlement proceedings.  See Note 3, Regulatory Actions, FERC Matters, of the Notes to Financial Statements for further discussion of these rate cases. 

 

   The One Nevada Transmission Line (“ON Line”)

 

As discussed earlier, the Utilities are currently constructing ON Line.  ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South.   The Joint Project consists of two phases.   In Phase 1 of the Joint Project, the parties will complete construction of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  The Utilities own a 25% undivided ownership interest in ON Line under the terms of the Transmission Use and Capacity Exchange Agreement (TUA) with GBT-South, which owns the remaining 75% undivided ownership interest in ON Line.  The Utilities’ 25% interest in ON Line, which approximates $138 million (based on the revised costs, discussed below) will be allocated 95% and 5% to NPC and SPPC, respectively.  The Utilities will have rights to 100% of the capacity of ON Line during Phase 1 (estimated to be approximately 600-800 MW).  If GBT elects to construct Phase 2, it would construct two additional transmission segments at either end of ON Line: one would extend from the Robinson Summit substation north to Midpoint, Idaho, and the other would commence at the Harry Allen substation and interconnect south at the Eldorado substation.  GBT would pay for and own 100% of Phase 2 facilities.   However, NPC and SPPC would have rights to transmission capacity from Midpoint to Eldorado (for a total of approximately 760 MW based on a rating of 2,000 MW for the completed Phase 1 and Phase 2 project).

 

In March 2012, NVE announced that the in-service date for ON Line would be delayed due to efforts to address wind-related damage sustained by some of the tower structures erected for the project.  On June 29, 2012, NPC filed its triennial 2013 – 2032 IRP with the PUCN.  The 2012 IRP included revised cost estimates for the ON Line project and provided an expected in-service date of no later than December 31, 2013.  The overall ON Line construction budget was revised from approximately $510 million to approximately $552 million before AFUDC.  The revised construction budget is based on the estimated cost of completing the project, including the costs for installation of mitigation measures identified to address the wind-induced vibration issues that delayed the project.  The Utilities requested PUCN approval of the decision to continue with construction of ON Line with the revised in-service date and revised budget. 

 

On December 24, 2012, the PUCN issued an order on NPC and SPPC’s IRP’s approving the Utilities’ request and finding that it was reasonable to continue with the construction of the ON Line project with the revised budget and according to the revised schedule, subject to certain conditions described below under Integrated Resource Plan

 

 

 

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   Regional Planning

 

The Utilities are members of the WestConnect Subregional Transmission Planning Committee.  This planning committee was established to provide coordinated transmission planning across the WestConnect footprint, including the Southwest Area Transmission Group, in which NPC participates, and the Sierra Subregional Planning Group, in which SPPC participates.

 

In October 2012, NPC and SPPC submitted a compliance filing to the FERC reflecting their participation with other jurisdictional utilities in the WestConnect Planning Management Committee relating to certain FERC Order 1000 requirements.  FERC Order 1000, issued in July 2011, establishes certain procedural and substantive requirements relating to participation, cost allocation and non-incumbent developer aspects of regional and inter-regional electric transmission planning activities. 

 

Integrated Resource Plan  

 

The Utilities are required to file IRPs every three years, and as necessary, may file amendments to their IRPs.  The IRPs are prepared in compliance with Nevada laws and regulations and cover a 20-year period.  The IRPs develop a comprehensive, integrated plan that considers customer energy requirements and propose the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals.  The ultimate goal of the IRPs is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of NPC’s and SPPC’s customers.  Projects approved through the IRP process still remain subject to prudency review by the PUCN.   The ESP, discussed in detail later, operates in conjunction with the IRP.  It serves as a guide for near-term execution and fulfillment of energy needs.

 

    NPC Electric

 

                In December 2012, the PUCN issued its order on NPC’s 2012 IRP, which included the following significant items:

 

Approval to proceed with the construction of ON Line with the revised budget ($552 million, excluding AFUDC) and according to the revised schedule (expected in service date of no later than December 31, 2013), assuming a satisfactory resolution of the wind-induced vibration issues.

Approval to defer the difference between the actual monthly payment to GBT and the monthly payment amount excluding all costs arising from the wind-induced vibration into a deferred regulatory asset  for later investigation and disposition.  The Utilities are authorized to accrue carrying charges on the portion of the deferred balance that is ultimately found by the PUCN to be prudently incurred. 

Approval of various DSM programs to increase energy efficiency and conservation programs totaling approximately $6.0 million over the remaining one year action plan.

Deferred approval of NPC’s proposal to issue an RFP for additional renewable energy contracts for no more than 100 MW, subject to a PUCN rulemaking docket associated with the portfolio standard and resource planning process.

Approval of the long-term load forecast and the three-year forecast.

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   SPPC Electric

 

SPPC’s 2010 triennial IRP as amended includes the following significant items:

 

Approval of the long-term load forecast and the three-year forecast.

A finding that the sale of the California Assets to CalPeco is in the public interest of Nevada, authorizing and accepting the accounting adjustments and ratemaking treatment proposed by SPPC and authorizing entry into and performing transactions necessary to accomplish the sale of the California Assets to CalPeco. The sale of the California Assets was completed in January 2011.  See Note 15, Assets Held for Sale, of the Notes to Financial Statements. 

Authority to modify retirement dates for eleven remote generation facilities and retire and decommission ten remote generation facilities and to accumulate the costs of decommissioning and remediating the remote generation sites in separate regulatory assets subaccounts for recovery in a future GRC proceeding.

Affirmed the funding level for a transmission project approved in SPPC’s 2007 IRP filing of approximately $30 million.

Approval of DSM programs scopes, budgets, timetables and measures and the Demand Side Plan.

Similar approvals for ON Line, as discussed above under NPC.

 

Energy Supply Planning

 

     General 

 

The energy supply function at the Utilities encompasses the reliable and efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource optimization (e.g., physical and economic dispatch).

 

There is the potential for continued price volatility in each Utility’s service territory, particularly during peak periods.  Too great a dependence on generation from the wholesale market can lead to power price volatilities depending on available power supply and prevailing gas prices.  Both Utilities face load obligation uncertainty due to the potential for customer switching.  Some counterparties in these areas have significant credit difficulties, representing credit risk to the Utilities.  Finally, each Utility’s own credit situation can have an impact on its ability to enter into transactions.

 

In response to these energy supply challenges, the Utilities have adopted an approach to managing the energy supply function that has three primary elements.  The first element is a set of management guidelines to procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation.  The second element is an energy risk management and risk control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control; and ensures clear distinction between policy setting (or planning) and execution.  Lastly, the Utilities will pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans.

 

Within the energy supply planning process, there are three key components covering different time frames:

 

1.

 

The PUCN-approved long-term IRP, which is filed every three years, has a twenty-year planning horizon;

2.

 

The PUCN-approved ESP which is an intermediate term resource procurement and risk management plan that establishes the supply portfolio strategies within which intermediate term resource requirements will be met, has a one to three year planning horizon; and

3.

 

Tactical execution activities with a one-month to twelve-month focus.

 

The ESP operates in conjunction with the PUCN-approved twenty-year IRP.  It serves as a guide for near-term execution and fulfillment of energy needs.  When the ESP calls for executing contracts of longer than three years, PUCN approval is required.

 

In developing and executing ESPs, management guidelines followed by the Utilities include:

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 •

 

Maintaining an ESP that minimizes supply costs and retail price volatility and maximizes reliability of supply over the term of the ESP;

 

Investigating feasible commercial options to execute the ESP;

 

Applying quantitative techniques and diligence commensurate with risk to evaluate and execute each transaction;

 

Monitoring the portfolio against evolving market conditions and managing the resource optimization options; and

 

Ensuring transparent and well-documented decisions and execution processes.

 

   Energy Risk Management and Control

 

The Utilities’ efforts to manage energy commodity (electricity, natural gas, coal and oil) price risk are governed by the BOD's revised and approved Enterprise Risk Management and Control Policy.  That policy created the EROC and made that committee responsible for the overall policy direction of the Utilities’ risk management and control efforts.  That policy further instructed the EROC to oversee the development of appropriate risk management and control policies, including the Energy Risk Management and Control Policy.

                 

The Utilities’ commodity risk management program establishes a control framework based on existing commercial practices.  The program creates predefined risk thresholds and delineates management responsibilities and organizational relationships.  The program requires that transaction accounting systems and procedures be maintained for systematically identifying, measuring, evaluating and responding to the variety of risks inherent in the Utilities’ commercial activities.  The program’s control framework consists of a disclosure and reporting mechanism designed to keep management fully informed of the operation’s compliance with portfolio and credit limits.

                 

Currently, the Utilities are not operating under a PUCN-approved hedging plan, nor are they hedged against commodities.  However, the Utilities may purchase and sell financial instruments and physical products to maintain an energy risk management program that limits energy risk to levels consistent with ESPs approved by the CEO and the EROC.

 

   Intermediate Term ESPs

 

The Utilities update their intermediate term ESPs annually. In June 2012, NPC filed its 2013-2015 ESP, and in August 2012, SPPC filed its ESP update for 2013. Both plans were approved by the EROC and the CEO prior to submission to the PUCN. 

 

The summer needs of 2013 for both Utilities will be met through a portfolio consisting of self-generation, forward contracts for power and peaking and seasonal capacity, or synthetic tolling based contracts (e.g., power prices indexed to gas prices) while striving to provide the lowest cost energy within reliability and transmission constraints.

 

   Long-Term Purchased Power Activities

 

                The Utilities update their respective planning documents (IRPs, ESPs, and the Portfolio Standard Annual Report) on a regular and as needed basis to determine their energy and PEC needs.   When the planning documents call for long term purchased power and/or PEC agreements, RFPs are issued, bids are evaluated, and contracts are executed with the successful bidders.  Contracts requiring PUCN approval are submitted to the PUCN as part of the IRP or an amendment to an IRP.  Long-term purchased power contracts are discussed in more detail earlier, under Purchased Power

 

   Short-Term Resource Optimization Strategy

 

The Utilities’ short-term resource optimization strategy involves both day-ahead (next day through the end of the current month) and real-time (next hour through the end of the current day) activities that require buying, selling and scheduling power resources to determine the most economical way to produce or procure the power resources needed to meet the retail customer load and operating reserve requirement.  The Utilities commit and dispatch generating units based on the comparative economics of generation versus spot-market purchase opportunities.  Any amount of excess capacity or energy is sold on the wholesale market, while any deficient capacity or energy position is filled by either buying on the spot market or utilizing available generating capacity.

 

                The day-ahead resource optimization begins with an analysis of projected hourly loads, existing resources and operating reserve requirements.  Firm forward take-or-pay contracts are scheduled and counted towards meeting the capacity needs of the day being pre-scheduled.  The day-of resource optimization involves minimizing system production costs each hour by lowering or raising generating unit output or buying power and/or selling excess power in the wholesale market all in order to meet the system load requirement and operating reserve requirement.  Any sale of excess power priced above the incremental cost of producing such power

24

 


 

 

 

reduces the net production cost of operating the electrical system and thereby benefits the end use customer.  The Utilities endeavor to reduce the electrical systems’ net production cost by selling available excess energy when it exists.

 

                Real-time resource optimization requires an hourly determination of whether to increase or decrease the loading of on-line generating units, commit previously off-line generating units, un-commit on-line generating units, sell excess power, or purchase power in the real-time market to meet the companies’ resource needs.  In order to achieve the lowest production cost, the projected incremental or decremental cost of the next available generation resource options are compared to determine the lowest cost option.

 

Construction Program

 

NVE’s and the Utilities construction programs and estimated expenditures are subject to continuing review, and are periodically revised to include the rate of load growth, construction costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in Nevada, regulatory considerations and impact to customers, NVE’s and the Utilities’ ability to raise necessary capital, and changes in environmental regulations.  Under the Utilities’ franchise agreements, they are obligated to provide a safe and reliable source of energy to their customers.  Capital construction expenditures and estimates are reflective of the Utilities’ obligation to serve their customer base.  Estimated construction expenditures may change depending on additional resources needed by the Utilities as disclosed in the Load and Resources table, earlier.

 

Gross construction expenditures for 2012, including AFUDC-debt, net salvage and CIAC, were $498.9 million, $287.6 million and $211.3 million for NVE, NPC and SPPC, respectively, and for the period 2008 through 2012, were $4.1 billion, $3.2 billion and $907.8 million, respectively.  Cash requirements related to construction projects in 2012 for NVE, NPC and SPPC were $414.3 million, $245.2 million and $169.1 million, respectively. Estimated construction expenditures for PUCN approved projects, projects under contract, environmental compliance projects and other base capital requirements are as follows (dollars in thousands):

25

 


 

 

 

 

NVE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric Facilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Generation  (1) 

$

183,239 

 

$

146,707 

 

$

130,620 

 

$

155,026 

 

$

156,340 

 

Distribution

 

139,695 

 

 

141,363 

 

 

132,807 

 

 

135,660 

 

 

137,998 

 

Transmission

 

85,749 

 

 

28,409 

 

 

62,317 

 

 

81,634 

 

 

106,005 

 

Environmental  (2) 

 

6,317 

 

 

30,262 

 

 

48,374 

 

 

15,472 

 

 

 

Other

 

61,187 

 

 

58,724 

 

 

72,564 

 

 

40,921 

 

 

60,791 

Total

 

476,187 

 

 

405,465 

 

 

446,682 

 

 

428,713 

 

 

461,134 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Facilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distribution

 

10,909 

 

 

10,162 

 

 

10,084 

 

 

10,070 

 

 

10,008 

 

Other

 

286 

 

 

286 

 

 

286 

 

 

287 

 

 

285 

Total

 

11,195 

 

 

10,448 

 

 

10,370 

 

 

10,357 

 

 

10,293 

Common Facilities

 

27,937 

 

 

27,935 

 

 

22,724 

 

 

11,247 

 

 

9,283 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

$

515,319 

 

$

443,848 

 

$

479,776 

 

$

450,317 

 

$

480,710 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

Generation for 2013 includes the termination payment for Reid Gardner Generating Station Unit No. 4, which is co-owned with

  

CDWR at December 31, 2012.  See Note 5, Jointly Owned Facilities, of the Notes to Financial Statements.

(2)

Environmental capital forecasts are in accordance with NDEP approved timelines which are pending federal approval.

 

Total estimated cash requirements related to NVE construction projects consist of the following (dollars in thousands):

 

 

 

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Construction Expenditures

 

$

515,319 

 

$

443,848 

 

$

479,776 

 

$

450,317 

 

$

480,710 

Net Salvage/Cost of Removal

 

 

9,382 

 

 

8,713 

 

 

9,798 

 

 

8,488 

 

 

8,627 

Net Customer Advances and CIAC

 

 

(74,164)

 

 

(65,545)

 

 

(71,664)

 

 

(65,538)

 

 

(69,057)

 

Total Cash Requirements

 

$

450,537 

 

$

387,016 

 

$

417,910 

 

$

393,267 

 

$

420,280 

                                 

 

NPC

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

2014 

 

2015 

 

2016 

 

2017 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric Facilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Generation

$

 136,781 

 (1) 

$

 102,976 

 

$

 80,674 

 

$

 89,437 

 

$

 111,964 

 

Distribution

 

 72,795 

 

 

 71,389 

 

 

 67,263 

 

 

 67,771 

 

 

 73,603 

 

Transmission

 

 64,319 

 

 

 12,653 

 

 

 39,759 

 

 

 78,406 

 

 

 103,032 

 

Environmental (2)

 

 1,935 

 

 

 12,528 

 

 

 21,192 

 

 

 10,054 

 

 

 - 

 

Other

 

 44,818 

 

 

 46,285 

 

 

 37,547 

 

 

 19,545 

 

 

 18,002 

Total

$

 320,648 

 

$

 245,831 

 

$

 246,435 

 

$

 265,213 

 

$

 306,601