10-K 1 form10-k.htm FORM 10-K form10-k.htm
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, 2011
             
       
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  o     
     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.  o
     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 o
Sierra Pacific Power Company: Large accelerated filer o  Accelerated filer o Non-accelerated filer þ  Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2011: $3,622,247,595
Indicate the number of shares outstanding of each of the issuer’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, 2012:  235,999,750 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 10, 2012, 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
2011 ANNUAL REPORT ON FORM 10-K

 
Page
   
4
         
PART I
 
         
ITEM 1.
6
ITEM 1A.
28
ITEM 1B.
33
ITEM 2.
34
ITEM 3.
35
ITEM 4.
35
         
PART II
 
         
ITEM 5.
36
ITEM 6.
38
ITEM 7.
40
   
43
   
NV Energy, Inc.
 
     
53
     
53
     
54
   
Nevada Power Company
 
     
59
     
65
     
66
   
Sierra Pacific Power Company
 
     
71
     
77
     
78
ITEM 7A.
83
ITEM 8.
85
   
86
   
NV Energy, Inc.
 
     
89
     
90
     
92
     
93
   
Nevada Power Company
 
     
94
     
95
     
97
     
98
   
Sierra Pacific Power Company
 
     
99
     
100
     
102
     
103
   
Notes to Financial Statements
 
     
104
     
110
     
112
     
121
     
121
     
123
 
 
 
 
 
     
127
     
127
     
129
     
131
     
135
     
141
     
145
     
149
     
150
     
150
     
151
     
152
ITEM 9.
153
ITEM 9A.
154
ITEM 9B.
156
         
PART III
 
         
ITEM 10.
156
ITEM 11.
157
ITEM 12.
157
ITEM 13.
157
ITEM 14.
157
         
PART IV
 
         
ITEM 15.
158
     
 
159



 

 
(The following common acronyms and terms are found in multiple locations within the document)
     
Acronym/Term
 
Meaning
     
2011 Form 10-K
 
NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2011
2012 Proxy Statement
 
NVE’s, NPC’s and SPPC’s Proxy Statement for 2012
AFUDC-debt
 
Allowance for borrowed funds used during construction
AFUDC-equity
 
Allowance for equity funds used during construction
BCP
 
Nevada Bureau of Consumer Protection
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
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
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
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
 
$600 million Revolving Credit Facility entered into in April 2010 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
OATT
 
Open Access Transmission Tariff
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
SPC
 
Sierra Pacific Communications
SPPC
 
Sierra Pacific Power Company d/b/a NV Energy
SPPC Credit Agreement
 
$250 million Revolving Credit Facility entered into in April 2010 between SPPC and Bank of America, 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
SPR
 
Sierra Pacific Resources
SRSG
 
Southwest Reserve Sharing Group
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
WECA
 
Western Energy Crisis Adjustment
WSPP
 
Western Systems Power Pool 
 

 

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.  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 2011 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. 
 
 

 
Overview

NPC and SPPC are public utilities that generate, transmit and distribute electric energy in Nevada and, in the case of SPPC, also delivers natural gas service.  At year-end 2011, NVE served approximately 1.2 million electric customers, of which 840,000 electric customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas were served by NPC, and approximately 323,000 electric customers in an approximate 50,000 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 152,000 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 Territory

Beginning in 2006, the Utilities embarked on a three part energy strategy to manage resources against their load by encouraging energy efficiency and conservation programs, the purchase and development of renewable energy projects, construction of generating facilities and expanding transmission capability in an effort to reduce their reliance on purchased power.  This strategy was initiated at a time when the Utilities were experiencing high growth which required significant capital investment in order to meet customer demands and also to establish self sufficiency and energy independence by building our own generating stations.  As customer growth and demand have stabilized, the Utilities are transitioning from an emphasis on capital investment  to an emphasis on optimizing our assets and resources.  A key element in the evolution of our energy strategy will be our ability to control both operating and maintenance expense as well as capital spending.  
 
 
 

Executing the evolution of the energy strategy

The completion of the Harry Allen Generating Station marked a notable transition in the evolution of our strategy.  Outlined below is the evolution of our energy strategy:

                                            Three Part Energy Strategy------------------------------------------------------------------------------------------------àEvolution of Energy Strategy
Increase energy efficiency, conservation
Empower customers through more focused energy efficiency programs
Expand renewable energy initiatives and investments
Pursue cost-effective renewable energy initiatives
Add new generation and transmission
Optimize generation efficiency and transmission
 
Engage employees to improve processes, reduce costs and enhance performance

             Empower customers through focused energy efficiency programs

The Utilities will continue with the implementation of NV Energize which not only provides metering and customer service operating savings, but will also provide customers with better opportunities to become more energy efficient.  NVE’s traditional conservation and energy efficiency programs, which have focused on behavioral change and technology replacement, will be enhanced by the new features enabled by NV Energize.  Customers will have access to better information to help them manage their usage and select from enhanced energy efficiency options, including demand response and pricing programs.  In 2011, NVE installed approximately 695,000 smart meters in southern Nevada and expects to have 1.4 million installed statewide by the end of 2012.  The NV Energize capabilities will allow NVE to help customers implement the most cost-effective mix of energy efficiency and conservation options that will also qualify toward fulfillment of the Portfolio Standard.
     
           Pursue cost-effective renewable energy initiatives

NVE must strive to effectively balance the need to meet the Portfolio Standard, with the changes in load forecast and the uncertainty of renewable energy project development, either for financial or resource related reasons. While NVE is better positioned to meet this challenge based on recent renewable successes, NVE remains committed to incorporating clean, cost-effective renewable energy into its portfolio.  As part of this continued commitment, NVE will continue to seek the best and most cost effective opportunities that will benefit our state, customers and environment. Depending on its needs and continuous analysis of the existing portfolio, NVE has a number of tools available to seek renewable energy values for our customers.  These tools may include issuing requests for proposals for new renewable energy contracts, exploring opportunities to either jointly construct or develop projects using wind, geothermal and solar, undertaking additional short-term purchases from existing renewable facilities and restructuring existing renewable relationships for the benefit of our customers.

The Portfolio Standard requires a specific percentage of an electric service provider’s total retail energy sales to be obtained from renewable energy resources. Renewable resources include biomass, geothermal, solar, waterpower, wind and qualified recovered energy generation projects. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the portfolio percentage. In 2012, the Utilities are required to obtain an amount of PECs equivalent to 15% of their total retail energy from renewables. Currently, the Portfolio Standard increases to 18% for 2013 and 2014, to 20% in 2015, after which it increases to 22% for the years 2020 through 2024, and to 25% for 2025 and beyond. Moreover, not less than 5% of the total Portfolio Standard must be satisfied from solar resources until 2016 when a minimum of 6% must be solar.

The Utilities acquire PECs through competitively-priced purchase power contracts, investments in renewable generating facilities and DSM programs.  NVE seeks to meet the standard using the most cost-effective means for our customers and to pursue the best-value options that are available to the Utilities.  In addition to the foregoing, this may also include economical short-term purchases of PECs (usually from outside of Nevada) to fulfill projected shortfalls due to the attrition or timing of development of renewable energy projects, weather variability or other supplier issues.

Optimize generation efficiency and transmission facilities

Since 2006, when NVE began its energy independence initiative, we have added over 3,800 MWs (nominally rated) of internal generation and, with the completion of Harry Allen Generating Station, NVE may obtain approximately 80% of its energy from internal generation.  In 2012, NVE’s management will continue 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 economical 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 2012.  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.
 
 

 
NVE will continue with the construction of the ON Line which will enable us to optimize our transmission capabilities.  Upon completion, the 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 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 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 $127 million, will be allocated 95% and 5% to NPC and SPPC, respectively.  The Utilities will have rights to 100% of the capacity of ON Line, which is estimated to be approximately 600 MW.  If GBT elects to construct Phase 2, it would construct two additional transmission segments at either end of ON Line: one extending from Robinson Summit north to Midpoint, Idaho, and the other commencing at the Harry Allen substation and interconnecting south to the Eldorado substation.  GBT would pay for and own 100% of Phase 2 facilities.  However, NPC and SPPC would have rights to additional transmission capacity from Midpoint to Eldorado (for a total of approximately 760 MW based on a rating of 2,000 MW for the complete path).

In February 2012, NVE announced ON Line will be delayed by at least three months.  ON Line was previously expected to be in service by December 31, 2012.   The delay is attributed to addressing recent wind-related damage sustained by some of the tower structures.  As a result of the damage and as a precautionary measure, the ON Line owners have directed construction crews to lay down certain existing tower structures and cease erection of further tower structures until the owners have completed an assessment of the situation.  Other construction activities that are focused on safety and are unrelated to the wind-damage are continuing while the owners work to resolve and repair the wind-related damage, ascertain the root causes of the damage, and otherwise determine what project modifications will be necessary to ensure project safety and reliability.  As a result, NVE is also delaying the merger application of the Utilities.

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 the evolution of our energy strategy.  Our goal is to maintain, 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 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 either recover or refund electric balances that have been deferred and that represent the difference between fuel and purchased power costs actually incurred and the amounts collected in current retail rates.  Additionally, the Utilities may file to reset BTERs quarterly, based on the last 12 months fuel and purchased power costs.  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 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 filed their first rate case with respect to this new regulation, referred to by the Utilities as the EEIR and EEPR, in October 2010 and will continue to file rate cases annually in March, thereafter.  In 2011, the Legislature passed Assembly Bill 215 which allows 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.  The Utilities will still be required to file an annual DEAA case 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 quarterly rate change.  The PUCN approved the Utilities filings to implement quarterly changes to their DEAA rates.  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 1 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.  In the event a customer were to exit the system, we do not expect the departure to have a material impact on the Utilities net income.

   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, 2012, there were 17 large customers securing their own supplies.  These customers have a combined firm distribution load of approximately 5,982 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.
 
 
 
 
Sales

In 2011, NPC’s and SPPC’s electric revenues were approximately $2.1 billion and $716.4 million, respectively.  SPPC’s natural gas business accounted for approximately $172.5 million in 2011 operating revenues or 19.4% of SPPC’s total revenues.  NPC’s peak electric load decreased at an average annual growth rate of 0.3% over the past five years, while SPPC’s decreased by 2.3%.  In 2011, NPC’s and SPPC’s electric system peaks were 5,539 MW and 1,513 MW, respectively, compared to 5,604 MW and 1,611 MW, respectively, in 2010.  NPC’s total retail electric MWh sales have decreased at an average annual growth rate of 0.3% over the past five years; and total retail electric MWh sales declined slightly in 2011 compared to 2010 as discussed below.  SPPC’s total retail electric MWh sales have decreased at an average annual growth rate of 2.6% over the past five years primarily due to a decrease in mining customers discussed below.

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

 
 
MWh Sales
 
 
 
2011
   
2010
   
2009
 
 
 
MWh
   
% of Total
   
MWh
   
% of Total
   
MWh
   
% of Total
 
Retail:
 
 
   
 
   
 
   
 
   
 
   
 
 
Residential
    8,523,321       41.1 %     8,684,386       41.6 %     8,893,542       41.8 %
 
                                               
Commercial & Industrial:
                                               
Gaming/Recreation/Restaurants
    3,171,853       15.3 %     3,215,710       15.4 %     3,392,658       16.0 %
All Other Retail
    8,834,305       42.5 %     8,742,166       41.9 %     8,670,931       40.8 %
Total Retail
    20,529,479       98.9 %     20,642,262       98.9 %     20,957,131       98.6 %
 
                                               
Wholesale
    -       -       1,262       -       69,915       0.3 %
Sales to Public Authorities
    225,518       1.1 %     231,072       1.1 %     240,302       1.1 %
Total
    20,754,997       100 %     20,874,596       100 %     21,267,348       100 %

Total retail MWh sales decreased approximately 0.5% in 2011 from 2010, primarily due to a decrease in customer usage due to milder summer weather in 2011 and conservation programs, partially offset by a slight increase in customers.  NPC’s average residential and commercial customers increased by 1.1% and 0.4%, respectively, while average industrial customers decreased by 1.9%.
 
    Although the unemployment rate remains above the national average in Las Vegas, the unemployment rate has improved significantly over the past year.  Additionally, the economy in Southern Nevada has begun to see another sign of improvement, as visitor volumes begin to return to levels seen in 2007 before the recession.  However, population growth is likely to be moderate until the economy strengthens both locally and nationally.

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

 
 
MWh Sales
 
 
 
2011
   
2010
   
2009
 
 
 
MWh
   
% of Total
   
MWh
   
% of Total
   
MWh
   
% of Total
 
Retail:
 
 
   
 
   
 
   
 
   
 
   
 
 
Residential
    2,231,107       26.9 %     2,465,049       30.4 %     2,502,537       30.5 %
 
                                               
Commercial & Industrial:
                                               
Mining
    1,578,195       19.0 %     1,506,866       18.6 %     1,405,087       17.2 %
All Other Retail
    3,838,649       46.3 %     4,108,834       50.6 %     4,254,749       51.9 %
Total Retail
    7,647,951       92.2 %     8,080,749       99.6 %     8,162,373       99.6 %
 
                                               
Wholesale
    631,569       7.6 %     13,797       0.2 %     14,993       0.2 %
Sales to Public Authorities
    16,061       0.2 %     16,459       0.2 %     16,535       0.2 %
Total
    8,295,581       100 %     8,111,005       100 %     8,193,901       100 %
 
Total retail MWh sales decreased approximately 5.4% in 2011 from 2010, primarily due to the sale of California Assets on January 1, 2011.  Excluding California, retail sales increased 1.5% in 2011, which are now reported in wholesale MWh sales.  Contributing to the increase in MWhs was a 2.0% increase in residential usage primarily due to colder weather, and a 4.8% increase in
 
 
 
11

 
mining usage in 2011.  Excluding California, SPPC’s average number of residential and commercial customers increased by 0.4% and 0.9%, respectively, while industrial customers decreased by 1.8%.

Mining is a leading industry in northern Nevada and comprises one of SPPC’s largest classes of customers.  In 2009, SPPC saw a decline in usage of mining customers as they switched to DOS service; however, in 2010 and 2011, mining customer usage increased as a result of a mining customer who restored operations in October 2009 and an increase in mining activity due to the elevated price of gold.
 
    Similar to southern Nevada, northern Nevada is seeing modest improvement in economic indicators and the economic recovery in the North is expected to be slow and dependent on the economy of neighboring states in addition to the national economy.

SPPC has long-term electric service agreements with eight of its largest commercial and industrial customers, with yearly revenues under these agreements totaling approximately $61 million.  For 2011, this represented approximately 8.5% of SPPC’s electric operating revenues of approximately $716.4 million.  Such agreements include requirements for customers to maintain minimum demand and load factor levels.  In addition, they include provisions to recover all investments for customer-specific facilities that have been made by SPPC on their behalf. 

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 SPPC under terms of a long-term service agreement, will 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.

   Heating Degree Days (HDD) and Cooling Degree Days (CDD)

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

The following table shows the heating degree days and cooling degree days within NPC’s and SPPC’s service territories for each of the last three years:

 
 
2011
 
2010
 
2009
 
 
 
 
Change From
 
 
 
Change From
 
 
 
 
Amount
 
 Prior Year
 
Amount
 
Prior Year
 
Amount
 
NPC
 
 
 
 
 
 
 
 
 
 
 
 
HDD
 
 2,040
 
7.7%
 
 1,895
 
0.3%
 
 1,889
 
 
CDD
 
 3,540
 
(3.0)%
 
 3,648
 
(3.7)%
 
 3,790
 
 
 
 
 
 
 
 
 
 
 
 
SPPC
 
 
 
 
 
 
 
 
 
 
 
 
HDD
 
 5,112
 
5.0%
 
 4,868
 
(2.7)%
 
 5,004
 
 
CDD
 
 964
 
4.6%
 
 922
 
(13.8)%
 
 1,069
 
 
 
 
 
 
 
 
 
 
 
 
Data Source: National Weather Service
 
 
 
 
 
 
 
 

Demand

   Load and Resources Forecast

NPC’s peak electric demand decreased in 2011 to 5,539 MWs from 5,604 MWs in 2010.  SPPC’s peak electric demand decreased in 2011 to 1,513 MWs from 1,611 MWs in 2010.  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 and 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 and contracts for purchased power.  Remaining needs will be met through power purchases through 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
 
 
 
12

 
achievement of commercial operation with respect to renewable energy power projects not yet commercially operable, as well as the intermittent reliability 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 Resource Optimization, 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, 2011, summarizing the forecasted summer electric capacity requirement and resource needs of the Utilities after consideration of energy conservation programs (assuming no curtailment of supply or load, and normal weather conditions) and the completion of ON Line, as discussed in the Transmission section later, subject to change:

   
Forecasted Electric Capacity Requirements and Resources (MW)
 
   
2012
   
2013
   
2014
   
2015
   
2016
 
NPC
 
 
   
 
   
 
   
 
   
 
 
   Total requirements(1)
    6,257       6,089       6,115       6,191       6,285  
                                         
Resources:
                                       
 Company-owned  generation(2)
    4,575       4,570       4,570       4,570       4,792  
 Contracts for power purchases
    1,706       1,640       1,417       1,417       1,195  
 Contracts for renewable energy power purchases, not
                                       
 yet commercially operable(3)
    32       76       167       180       180  
Total resources
    6,313       6,286       6,154       6,167       6,167  
                                         
Total additional required (additional resources)(4)
    (56 )     (197 )     (39 )     24       118  
 
(1)
Includes projected system peak load plus 12% planning reserves.  The decrease in total requirements from 2012 to 2013 is primarily due to an expected decrease in demand as a result of energy efficiency and conservation programs.
(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.
(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.

   
Forecasted Electric Capacity Requirements and Resources (MW)
 
   
2012
   
2013
   
2014
   
2015
   
2016
 
SPPC
 
 
   
 
   
 
   
 
   
 
 
Total requirements(1)
    1,853       1,863       1,863       1,884       1,812  
                                         
Resources:
                                       
Company-owned existing generation
    1,519       1,519       1,466       1,466       1,383  
Contracts for power purchases
    407       303       303       303       303  
Total resources
    1,926       1,822       1,769       1,769       1,686  
                                         
Total additional required (additional resources)(2)
    (73 )     41       94       115       126  
 
(1)
Includes projected system peak load plus 15% planning reserves.
(2)
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 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

NPC and SPPC Electric

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 2011, NPC generated 69.6% of its total system requirements, purchasing the remaining 30.4% as shown below and SPPC generated 50.5% of its total electric energy requirements, purchasing the remaining 49.5% as shown below.
 
   
2011
   
2010
   
2009
 
   
MWh
   
% of Total
   
MWh
   
% of Total
   
MWh
   
% of Total
 
NPC
 
 
   
 
   
 
   
 
   
 
   
 
 
Gas Generation
    11,687,714       54.1 %     11,666,152       53.6 %     12,793,249       57.8 %
Coal Generation
    3,346,506       15.5 %     3,739,339       17.2 %     3,632,385       16.4 %
Total Generated
    15,034,220       69.6 %     15,405,491       70.8 %     16,425,634       74.2 %
Total Purchased
    6,577,339       30.4 %     6,350,795       29.2 %     5,696,555       25.8 %
Total System(1)
    21,611,559       100.0 %     21,756,286       100.0 %     22,122,189       100.0 %

   
2011
   
2010
   
2009
 
   
MWh
   
% of Total
   
MWh
   
% of Total
   
MWh
   
% of Total
 
SPPC
 
 
   
 
   
 
   
 
   
 
   
 
 
Gas Generation
    3,254,453       36.9 %     3,707,666       43.0 %     3,852,662       43.4 %
Coal Generation
    1,199,121       13.6 %     1,412,875       16.3 %     1,729,466       19.5 %
Total Generated
    4,453,574       50.5 %     5,120,541       59.3 %     5,582,128       62.9 %
Total Purchased
    4,368,036       49.5 %     3,509,767       40.7 %     3,296,482       37.1 %
Total System(1)
    8,821,610       100.0 %     8,630,308       100.0 %     8,878,610       100.0 %

(1)  Included in Total System is expected energy waste resulting from the transmission of electrical energy across power lines.

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.  The Utilities decision to purchase this energy is based on economics, mitigation of availability risk, and transmission availability.  Firm block purchases are transacted 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 transmission availability.  

NPC’s total system decreased 0.7% in 2011 compared to 2010.  In 2011, NPC’s total generated decreased 2.4% from 2010 while purchased power MWhs increased 3.6% compared to 2010.   SPPC’s total system increased 2.2% in 2011 compared to 2010.  In 2011, SPPC’s purchased power total MWhs increased 24.5% compared to 2010, while generation decreased 13%.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding the Utilities’ total system.  Also see Energy Supply, later, for discussion of the Utilities purchasing strategies.

   Generation

In 2011, NPC completed construction of a 484 MW (summer peak) combined cycle natural gas generating station at the existing Harry Allen Generating Station. Sunrise Station Units 1 & 2 (summer peak 150 MW) were retired with PUCN approval on December 31, 2011.

NPC’s generation capacity consists of a combination of 44 gas and coal generating units with a combined summer capacity of 4,343 MWs as described in Item 2, Properties.  In 2011, NPC generated 69.6% of its total system requirements. 

SPPC’s generation capacity consists of a combination of 19 gas, oil and coal generating units with a combined summer capacity of 1,519 MWs as described in Item 2, Properties.  In 2011, SPPC generated 50.5% of its total system requirements.
 
 
 
 
   Fuel Sources

The Utilities’ 2011 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 2007 through 2011, along with the percentage contribution to the Utilities’ total fuel sources were as follows:

NPC Electric
 
 
Average Consumption Cost & Percentage Contribution to Total Fuel
 
 
 
 
Gas
 
Coal
 
 
 
 
$/MMBtu
 
Percent
 
$/MMBtu
 
Percent
 
 
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%
 
 
2007
 
6.32
 
64.4%
 
1.89
 
35.6%
 
 
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.

In 2011, NPC transitioned from a three season ahead physical gas laddering strategy to 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.  The physical gas is procured at an appropriate industry index during the month of current delivery.  No fixed price transactions were executed during 2011. All 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.

NPC utilizes a laddered strategy with respect to coal supply and has two long term coal contracts with Arch Coal Sales Company and one with Andalex Resources, Inc.  These contracts represent 90% of projected coal requirements for 2012, 68% for 2013 and 12% for 2014.

As of December 31, 2011, NPC’s Reid Gardner Generating Station coal inventory level was 237,970 tons, or approximately 70 days of consumption at 100% capacity.

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

Coal for the Navajo Generating Station, which is jointly owned by six entities and operated by Salt River Project, is obtained under a Coal Sales Agreement with Peabody Coal Company that extends through 2019. Coal is supplied from surface mining operations conducted on Navajo Nation and Hopi Tribe reservation lands on the Black Mesa in Arizona.

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 2011, for generating stations located in NPC’s control area, seasonal and monthly gas supply net purchases averaged approximately 268,428 Dth per day, with the winter period contracts averaging approximately 219,492 Dth per day, and the summer period contracts averaging approximately 302,958 Dth per day.

Listed below is NPC’s transportation portfolio as of December 31, 2011:

 
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
 
5,200
 
Summer
 
 
 
Southwest Gas
 
45,000
 
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
 
 
 
 
Gas
 
Coal
 
 
 
 
$/MMBtu
 
Percent
 
$/MMBtu
 
Percent
 
 
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%
 
 
2007
 
8.34
 
58.0%
 
1.93
 
42.0%
 

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.

Similar to NPC discussed above, in 2011, SPPC transitioned to a four season ahead laddering strategy to procure gas.  No fixed price transactions were executed during 2011.  Therefore, the physical gas prices are set at an appropriate industry index during the month of current delivery.  All 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 utilizes a laddered strategy with respect to coal supply and has long-term coal contracts with Black Butte Coal Company and Arch Coal Sales Company.  These contracts represent 100% of the Valmy Generating Station’s projected coal requirements in 2012, 65% for 2013, 50% for 2014, and 40% for 2015.

A Transportation Services Contract with Union Pacific Railroad Company that provides for deliveries from the Provo, Utah interchange, as well as various mines in Utah, Colorado and Wyoming, to the Valmy Generating Station in Valmy, Nevada extends through 2014.

As of December 31, 2011, the coal inventory level at Valmy Generating Station was 359,066 tons or approximately 132 days of consumption at 100% capacity.

      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 190,735 Dth per day for the winter of 2011/2012.

To secure gas supplies for the 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 laddering strategy discussed above.  In 2011, seasonal and monthly gas supply net purchases averaged approximately 114,617 Dth per day with the winter period contracts averaging approximately 136,169 Dth per day, and the summer period contracts averaging approximately 99,409 Dth per day.

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 2010 through October 2011 and November 2011 through October 2012, 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 are the current gas transportation and storage service agreements:

 
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 2011 and 2010 were 16.7 million Dth and 14.7 million Dth, respectively.  Electric generating fuel requirements for 2011 and 2010 were 25.9 million Dth and 29.0 million Dth, respectively.

   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 2011, NPC and SPPC purchased approximately 30.4% and 49.5%, 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 2,481 MW and contract termination dates ranging from 2013 to 2038.  Included in these contracts are approximately 886 MW of nameplate capacity of renewable energy of which approximately 649 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 2011.

      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 400 MW and contract termination dates ranging from 2016 to 2039.  Included in these contracts are approximately 210 MW of nameplate capacity of renewable energy of which approximately 20 MW of nameplate capacity are under construction and not currently available.  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.  
 
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 2011.

 Transmission

            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 west.  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, Southern California Edison, 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, Southern California Edison, PacifiCorp, Bonneville Power Administration, Pacific Gas & Electric and Plumas-Sierra Rural Electric Cooperative.  

The service territories of NPC and SPPC are not directly interconnected at present; however, in February 2011, NVE and the Utilities entered into an agreement with Great Basin Transmission (GBT) to construct ON Line, which will interconnect the systems for the first time.

Under the NERC guidelines, 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 a 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
 
 
 
18

 
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.

NPC and SPPC plan, build, and operate transmission systems that delivered 21,611,559 MWh and 8,821,610 MWh of electricity to customers, respectively, in their Balancing Authority Areas in 2011.  The NPC system handled a system peak load of 5,539 MW in 2011 through approximately 1,724 miles of transmission lines and other transmission facilities ranging from 60 kV to 500 kV.  The SPPC system handled a system peak load of 1,513 MW in 2011 through 1,987 miles of transmission lines and other facilities ranging from 60 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 OATT.  In accordance with the OATT, the Utilities offer several transmission services to wholesale 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), and
Network transmission service (equivalent to the service NVE provides for NVE’s bundled retail customers).

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.
 
   The One Nevada Transmission Line (“ON Line”)

As discussed earlier, the Utilities are currently constructing ON Line which would provide a 500 kV interconnection between a new Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  ON Line would further provide an interconnection between NPC and SPPC’s system and enhance our ability to optimize the use of our generation and transmission facilities in alignment with the evolution of our energy strategy.
 
 
ON Line Map
 
 
 
Regional Planning

The Utilities are members of WestConnect and the WestConnect Subregional Transmission Planning Committee.  WestConnect is a group of southwest transmission-providing utilities that have agreed to work collaboratively to assess stakeholder and market needs and to investigate, analyze and recommend to its Steering Committee implementation of cost-effective enhancements to the western wholesale electricity market.  The Subregional Transmission 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.

FERC issued Order 1000 on July 21, 2011.  Order 1000 establishes basic requirements for transmission planning on a regional and interregional basis. The Utilities are currently evaluating Order 1000 and participating in various regional processes in order to comply with the order.

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.  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 July 2010, the PUCN issued its order on NPC’s 2009 IRP, which included the following significant items:
 
Approval to jointly develop ON Line with GBT, an affiliate of LS Power, discussed earlier in the Transmission section.  The PUCN also approved NPC’s self-build option for ON Line if the companies and GBT were unable to reach agreement.  However, in February 2011, the Utilities and GBT finalized the agreement to jointly construct ON Line.
Granted NPC’s request for critical facility designation for its incremental operating and maintenance costs for ON Line.
Approval of NV Energize of approximately $95 million and $69 million (excluding AFUDC) for NPC and SPPC, respectively, which was contingent on successfully obtaining a grant of $138 million in federal funds from the DOE to co-fund the project.  A total grant of $139 million was obtained from the DOE in September 2010.
Approval to establish a regulatory asset for stranded non-advanced metering infrastructure electric meter costs related to NV Energize.
Approval of various DSM programs to increase energy efficiency and conservation programs totaling approximately $209.9 million over the three year action plan.
Accepted NPC’s proposal to postpone the EEC indefinitely, but ordered NPC to resubmit the request as a part of its next triennial IRP filing in July 2012.  In February 2011, NVE and the Utilities canceled plans to construct the EEC.
Approval of the long-term load forecast and the three-year forecast.

   SPPC Electric

In July 2010, as required by Nevada law, SPPC filed its 2010 triennial IRP with the PUCN.  In December 2010, the PUCN issued its order on SPPC’s IRP, which included 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 16, Assets Held for Sale, in 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 totaling approximately $36 million.
 
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:

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.

Beginning in October 2009, the Utilities suspended their hedging programs; however, prior to the suspension, it was the general policy of the Utilities to purchase hedges three seasons ahead.  As a result certain hedges entered into prior to the suspension in October 2009, did not terminate until 2011.  As of November 2011, all hedging transactions have expired or terminated and the Utilities remain unhedged.  If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   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.
 
  The Utilities, through the purchase and sale of financial instruments and physical products, 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 July 2011, NPC filed its ESP update for the period 2012, and in September 2011, SPPC filed its ESP update for the period 2012-2013. Both plans were approved by the EROC and the CEO prior to submission to the PUCN.

The summer needs of 2012 for both SPPC and NPC will be met through a portfolio mix 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 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 in the wholesale market if opportunities are available and the market price is lower than the production costs, 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 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 is compared to determine the lowest cost option.

Construction Program

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, 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.

Gross construction expenditures for 2011, including AFUDC debt, net salvage and CIAC, were $475.1 million and $145.4 million for NPC and SPPC, respectively, and for the period 2007 through 2011, were $3.7 billion and $1.1 billion, respectively.  Cash
 
 
 
22

 
requirements related to construction projects in 2011 for NPC and SPPC were $387.5 million and $134.7 million, respectively. Future estimated construction expenditures are as follows (dollars in thousands):

 
 
2012
   
2013
   
2014
   
2015
   
2016
 
NPC
 
 
   
 
   
 
   
 
   
 
 
     Electric Facilities:
 
 
   
 
   
 
   
 
   
 
 
     Generation
  $ 109,207     $ 148,464     $ 87,763     $ 69,254     $ 72,046  
     Distribution
    70,800       69,168       67,172       68,074       70,515  
     Transmission
    79,204       31,359       63,285       43,166       34,218  
     Other
    51,806       34,194       48,996       61,284       47,568  
     Total
  $ 311,017     $ 283,185     $ 267,216     $ 241,778     $ 224,347  

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

 
 
2012
   
2013
   
2014
   
2015
   
2016
 
 
 
 
   
 
   
 
   
 
   
 
 
Construction Expenditures
  $ 311,017     $ 283,185     $ 267,216     $ 241,778     $ 224,347  
AFUDC
    (8,091 )     (7,353 )     (6,775 )     (7,754 )     (11,437 )
Net Salvage / Cost of Removal
    3,292       3,090       2,917       2,621       2,384  
Net Customer Advances and CIAC
    (25,175 )     (15,090 )     (14,342 )     (12,887 )     (11,724 )
Total Cash Requirements
  $ 281,043     $ 263,832     $ 249,016     $ 223,758     $ 203,570  
 

SPPC
 
2012
   
2013
   
2014
   
2015
   
2016
 
     Electric Facilities:
 
 
   
 
   
 
   
 
   
 
 
  Generation
  $ 28,592     $ 64,568     $ 52,849     $ 28,315     $ 28,577  
  Distribution
    64,155       38,963       42,812       45,982       42,797  
  Transmission
    31,529       14,906       33,448       4,466       3,015  
  Other
    19,857       21,889       23,748       20,659       21,447  
    Total
    144,133       140,326       152,857       99,422       95,836  
                                         
    Gas Facilities:
                                       
  Distribution
    26,468       12,486       12,428       12,671       12,788  
  Other
    272       275       277       282       285  
    Total
    26,740       12,761       12,705       12,953       13,073  
    Common Facilities
    26,127       11,274       10,786       10,997       11,099  
    Total
  $ 197,000     $ 164,361     $ 176,348     $ 123,372     $ 120,008  

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

 
 
2012
   
2013
   
2014
   
2015
   
2016
 
Construction Expenditures
  $ 197,000     $ 164,361     $ 176,348     $ 123,372     $ 120,008  
AFUDC
    (6,297 )     (5,243 )     (7,561 )     (5,238 )     (3,871 )
Net Salvage / Cost of Removal
    4,914       4,046       4,324       3,026       2,975  
Net Customer Advances and CIAC
    (7,215 )     (8,041 )     (7,321 )     (5,124 )     (5,037 )
Total Cash Requirements
  $ 188,402     $ 155,123     $ 165,790     $ 116,036     $ 114,075  

Major projects included in the 5 year estimated construction expenditures above are as follows:
 
In 2010, the PUCN approved the NV Energize project. The project includes the deployment of a fully-integrated advanced metering infrastructure, a meter data management system, and a demand response management system.  Of the total $303 million dollars in projected costs, $139 million will be provided by the U.S. Department of Energy through its Smart Grid Investment Grant Program. The remaining $164 million will be provided by NPC and SPPC 70% and 30%, respectively.

In 2010, the PUCN approved the construction of ON Line project as discussed previously under the Transmission section.  As a joint owner of ON Line, NVE will be responsible for 25% of the projected costs of the $509 million project. The $127 million will be allocated to NPC and SPPC 95% and 5%, respectively.
 
 

 
NPC is a party to a joint development agreement with China Mountain Wind LLC, an affiliate of RES Americas, Inc., in connection with the China Mountain Wind Project.  Under the joint development agreement, NPC participates in the permitting and development of the China Mountain Wind Project near the Nevada-Idaho border and has the opportunity to participate in the construction and ownership of the project.  The PUCN has not yet approved the project, and as such, it has not been included in the above tables.

ENVIRONMENTAL (NVE, NPC AND SPPC)

As with other utilities, NPC and SPPC are subject to various environmental laws and regulations enforced by federal, state and local authorities.  The EPA, NDEP, the Southern Nevada Health District, and the Clark County Department of Air Quality and Environmental Management administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste.  Nevada’s Utility Environmental Protection Act also requires the Utilities to obtain approval of the PUCN prior to construction of major utility, generation or transmission facilities.  

From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations which address noise, emissions, impacts to air and water, protected and cultural resources, and solid, hazardous, and toxic waste. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations to ensure complete compliance.  The most significant environmental laws and regulations, both in effect and proposed, that could impact NPC and SPPC are discussed below:
 
Federal Environmental Laws, Regulations and Regulatory Initiatives

   Clean Air Standards

The Clean Air Act (CAA) provides a framework for protecting and improving the nation’s air quality and controlling mobile and stationary sources of air emissions.  The 1990 amendments to the CAA impose limitations on the emissions of sulfur dioxide (SO2), nitrogen oxide (NOX) as well as other pollutants.  All of the Utilities' fossil fuel generating stations are subject to these limitations and are in compliance with current standards.  Congress has from time to time considered legislation that would amend the CAA to target specific emissions from electric utility generating plants.  The EPA has also proposed potential regulations associated with these types of emissions.  If enacted, this legislation and/or regulations could require reductions in emissions of NOX, SO2, mercury and/or other pollutants.  The CAA programs which most directly affect the State of Nevada and NVE’s electric generating facilities are described below:

      Mercury and Air Toxics Standards (MATS)

In December 2011, the EPA signed for publication in the Federal Register a final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units.  The rule, referred to as the MATS rule requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the maximum achievable control technology (MACT). The rule becomes effective 60 days after publication in the Federal Register. Compliance with the MATS emission standards is required within 3 years of publication of the rule in the Federal Register. However, if an existing source is unable to comply within 3 years, the NDEP has the ability to grant up to a 1-year extension, if additional time is necessary for the installation of controls. The EPA also noted that the Clean Air Act provides additional flexibilities to bring sources into compliance while maintaining electric reliability, and published a memorandum on December 16, 2011 articulating the Agency’s intended approach with respect to sources that operate in noncompliance with the MATS Rule.

The final rule does not specifically list control technologies that are required to achieve the MATS emission standards. Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards.  At the present time, SPPC believes a dry sorbent injection system may be a viable control option for Unit 1, at an estimated capital cost of approximately $20 million.  Note that the actual cost could vary and will be dependent upon final engineering design.
 
 

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

The CAA requires the EPA to set minimum NAAQS for certain air emissions including ozone, particulate matter, SO2 and nitrogen dioxide (NO2).  The CAA established two types of NAAQS: (1) primary standards, which set limits to protect public health, and (2) secondary standards, which set limits to protect public welfare.  Most NAAQS require measurement over a defined period of time (typically one hour, eight hours, twenty-four hours, or one year) to determine the average concentration of the pollutant present in a defined geographic area.

When a NAAQS has been established, each state must recommend, and the EPA must designate, the areas within its boundaries that meet NAAQS (“attainment areas”) and those that do not (“non-attainment areas”).  Each state must develop a state implementation plan (“SIP”) to bring non-attainment areas into compliance with NAAQS and maintain good air quality in attainment areas.  The NAAQS that affect or potentially affect our Utility operations are summarized below.
 
           Ozone NAAQS

In March 2008, the EPA issued final rules adopting new, more stringent eight-hour NAAQS for ozone.  The EPA lowered the primary and secondary standards from 84 parts per billion to 75 parts per billion.   States are to submit plans to the EPA, no later than 2014, demonstrating attainment with the standard.  
 
In letters to state and tribal representatives dated December 2011, the EPA has identified which areas it anticipates will be meeting the 2008 ozone standards and those which are not.  States, tribes and the public will have an opportunity to comment on these proposed decisions before the agency issues final designations in spring 2012.  The Las Vegas/Clark County region is presently designated as non-attainment but it, as well as the rest of  Nevada, could be re-classified as attainment, based on the 2008 standard.  The next scheduled reconsideration of the ozone standard will likely occur in 2013. 

      Particulate Matter NAAQS

The EPA has developed annual NAAQS for coarse particulate matter (defined as particles of 10 micrometers or larger) and both annual and 24-hour NAAQS for fine particulate matter (particles with a size of up to 2.5 micrometers).   Nevada counties are currently meeting the particulate matter 2.5 standards. However, the Las Vegas/Clark County and Washoe County regions are in non-attainment for particulate matter 10 standards.  The EPA is currently reconsidering the annual fine particulate standard, and if lowered as expected, new non-attainment designations in our service territory could occur.   The EPA has indicated its reconsideration of the adequacy of the annual fine particulate matter 2.5 standard is expected to be completed in 2012.

     SO2 NAAQS

On June 22, 2010, the EPA established a new one-hour primary SO2 NAAQS at 75 parts per billion and revoked the 24 hour and annual SO2 NAAQS.  The 3-hour secondary NAAQS was established at 0.5 parts per million.  The EPA expects to designate areas as attainment, non-attainment, or unclassifiable in 2012 based on the existing monitoring network and modeling.  Non-attainment designations are expected to result in lower SO2 emission limits for sources of SO2 in or near those areas.

      NO2 NAAQS

On February 9, 2010, the EPA established a new one-hour NAAQS for NO2 at the level of 100 parts per billion.  To determine compliance with the new standard, the EPA is establishing new ambient air monitoring requirements near major roads as well as in other locations where maximum concentrations are expected.  Although existing air quality monitors do not currently show exceedances of this new standard in the Utilities’ service areas, additional community and roadside monitoring could result in the designation of new non-attainment areas.   The EPA intends to re-designate areas as soon as 2016, based on the air quality data from the new monitoring network.   In the February rulemaking, the annual primary and secondary annual NO2 NAAQS was maintained at 53 parts per billion.

Due to uncertainty regarding the potential stringency of any new NAAQS related proposals, NVE is not able to estimate cost impacts to its generating system at this time.  While the final outcome and timing for the EPA's and/or Congressional actions cannot be estimated, the Utilities continue to monitor the development of these standards and assess their potential impact on our generation fleet as new information becomes available.
 
 

 
      Regional Haze Rules 

In June 2005, the EPA finalized amendments to the July 1999 regional haze rules; thereby requiring states to develop SIPs to demonstrate compliance. These amendments apply to the provisions of the regional haze rule that require emission controls for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. States are required to identify the facilities that will have to reduce emissions through installation of emission controls, known as Best Available Retrofit Technology (BART), and then set emissions limits for those facilities. In 2008, the State of Nevada began its BART rule development and the proposed SIP to implement the BART requirements was released in the first quarter 2009.  As presented in the SIP, the impacted BART units are Reid Gardner Generating Station Units 1, 2 and 3; Ft. Churchill Generating Station Units 1 and 2; and Tracy Generating Station Units 1, 2 and 3.  The submitted BART SIP contains targeted emission rates and compliance with the state’s BART program can be achieved through options such as retrofit of emission reduction equipment on the affected units, or retirement of those units.  The Navajo Generating Station is also subject to BART and is currently awaiting an EPA rule determination.

On June 9, 2011, the EPA published in the Federal Register its draft proposal to approve Nevada's Regional Haze Plan as meeting the requirements of the Clean Air Act. However, in announcing its final approval in December 2011, the EPA opted to take no action specifically on the BART determination for nitrogen oxide (NOx) at the Reid Gardner Generating Stations, stating that it intends to propose action on those units at a later date and take public comment in the future.  The EPA’s final approval did include the State’s proposed BART determinations for SO2 and particulate matter for Reid Gardner Generating Station, as well as the BART controls proposed for all of the other NVE affected units.

Given the final EPA action in December, NVE is implementing the approved portions of the rule which will require compliance by January 1, 2015.  NVE intends to retire Tracy Generating Station Units 1 and 2 and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2.  A cost estimate is currently being prepared based on specific engineering specifications and designs.  It is anticipated that the EPA will request additional information prior to making the final determination on the Reid Gardner Generating Station NOx controls.  However, until the final determination is made, it is impossible to predict the effect the ruling may have on Reid Gardner Generating Station’s generating units.
 
Climate Change

                The topic of climate change continues to evolve, and response to this issue brings with it significant environmental, economic and social implications for NVE and other electric utilities.  Potential impacts from proposed legislation could vary, depending upon proposed carbon dioxide (CO2) emission limits, the timing of implementation of those limits, the program design, the degree to which offsets are allowed and available, and provisions for cost containment measures, such as a safety valve that provides a ceiling price for emission allowance purchases. However, the Utilities’ contribution of greenhouse gases (GHG) from its current generation fleet is partly mitigated due to our fuel portfolio being predominately natural gas which emits approximately 50% less CO2 than coal.
 
The impact on NVE and the Utilities of future initiatives related to GHG emissions and global climate change remains unknown. Although compliance costs are unlikely to be realized in the near future, federal legislative, federal regulatory, and state and regional-sponsored initiatives to control GHG emissions continue to progress, making it more likely that some form of control will eventually be required. For example, California is moving forward with the adoption of a proposed state cap on GHG emissions and developing market-based compliance mechanisms, including compliance offset protocols.
 
Since these initiatives continue to evolve, NVE has and will continue to identify projects that minimize or offset GHG emissions and believes that precautionary actions to limit GHG emissions are appropriate.

The EPA finalized regulations in September 2009 that require certain categories of businesses, including fossil fuel-fired power plants, to monitor and report their emissions beginning in 2011. NVE has been reporting its annual GHG emissions since it joined the California Climate Action Registry (CCAR) in 2006.  NVE also reported 2010 GHG emissions before the reporting deadline of September 30, 2011.  As required by the EPA, NVE will continue to report annual GHG emissions to comply with the federal mandatory GHG reporting program.

After a series of developments and rule proposals, in March of 2010, the EPA affirmed its position that the CAA permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V permit programs are not triggered for a pollutant until a regulatory requirement to control emissions of that pollutant becomes effective. As a result of this EPA determination, new or modified plants that were subject to PSD or Title V programs had to address GHG emissions in new permit applications as of January 2011. Similarly, GHG emitted above certain thresholds from existing plants were also covered under the Title V program beginning in January 2011. Currently, all NVE generation facilities have operating permits that could require modification to comply with the rule if modifications are undertaken. The extent to which this rule could have a material impact on our generating facilities depends upon whether physical changes or change in operations subject to the rule would occur at our generating facilities; future EPA determinations on what constitutes best available control technology for GHG emissions from power plants; and whether federal
 
 
 
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legislation is passed which overrides the rule.  During 2011, none of NVE’s generation facilities triggered the criteria specified in this rule.

On December 23, 2010 in a judicial settlement, the EPA announced that it will propose first-time GHG emission standards and guidelines for the power plant sector under the federal CAA.  Specifically, the agency expects to propose new source performance standards (NSPS) and emissions guidelines for existing sources for the power plant sector by May 2012.  It is reasonable to expect that the limits on GHG emissions imposed by the new source performance standards and guidelines for existing sources will have an impact on generating facility operations.  However, until the standards and guidelines are proposed, it is impossible to predict the potential effect on generating facility operations.

   Clean Water Act Standards

The EPA administers rules establishing aquatic protection requirements for power generation facilities that withdraw and discharge large quantities of water from and into rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes.  In consideration of the desert environment in which the Utilities operate, none of the Utilities’ generation plants employ “once through” cooling water intake/discharge structures into public water bodies.  Further, all of the Utilities’ generation stations are designed to have either minimal or zero water discharge into the surrounding environment.  Therefore, the various laws regulating “once through” cooling water intake structures and thermal discharges of wastewater from power generation facilities do not specifically apply to the NPC and SPPC generation sites.

The EPA is currently developing revised effluent limitation guidelines and standards for the steam electric power generating industry, which the agency expects to propose in July 2012.  The EPA's revision of these guidelines is driven primarily by concern over wastewater discharges from coal-fired power plants, but will also address discharges from ash ponds and flue gas desulfurization air pollution controls.  Under the terms of a related court-approved consent decree, the final rules must be published by January 31, 2014.  It is reasonable to expect that the new guidelines will impose more stringent limits on wastewater discharges from coal-fired power plants and ash ponds.  However, until the revised guidelines are proposed, it is impossible to predict the effect the revised guidelines may have on generating facility operations.

   Coal Combustion Product (CCP) Management

In 2010, the EPA released the text of a proposed rule describing two possible regulatory options it is considering under the Resource Conservation and Recovery Act (RCRA) for the disposal of coal ash generated from the combustion of coal by electric utilities and independent power producers.  Under either option, the EPA would regulate the construction of impoundments and landfills, and seek to ensure both the physical and environmental integrity of disposal facilities; however, none of the Utilities’ coal facilities currently manage ash in surface water impoundments; rather, these ash products are handled and processed in a dry form at both the Reid Gardner and Valmy Generating Stations.
 
The Utilities believe it is possible that the EPA will continue to allow some beneficial use, such as recycling of ash, without classifying it as hazardous waste. However, any additional regulations which more stringently regulate the management disposal or reuse of coal ash will likely increase costs for NVE’s coal generation facilities if the ability to recycle this material is impaired or current landfill disposal requirements are modified. Due to the uncertainties of how this material may ultimately be regulated in the future, the Utilities are unable to predict the outcome any such regulations might have on their systems at this time.
 
      Remediation Activities

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

NVE and its subsidiaries had 2,811 employees as of January 26, 2012, of which 1,614 were employed by NPC, and 1,092 were employed by SPPC.

NPC and IBEW 396, which covers approximately 57% of NPC’s workforce, have entered into a new collective bargaining agreement (CBA).  The CBA is effective September 1, 2011 through January 31, 2013.
 
On August 12, 2010, SPPC and IBEW Local 1245, which covers approximately 59% of SPPC’s workforce, entered into a new CBA.  The CBA is effective August 16, 2010 for a three-year period ending August 15, 2013.  
 
GENERAL – FRANCHISES (NPC AND SPPC)

The Utilities have nonexclusive local franchises or revocable permits to carry on their business in the localities in which their respective operations are conducted in Nevada.  The franchise and other governmental requirements of some of the cities and counties in which the Utilities operate provide for payments based on gross revenues.  Public utilities are required by law to collect from their customers a universal energy charge (UEC) based on consumption.  The UEC is designed to help those customers who need assistance in paying their utility bills or need help in paying for ways to reduce energy consumption. During 2011, the Utilities collected $130.0 million in franchise or other fees based on gross revenues.  They collected $9.5 million in UEC based on consumption. They also paid and recorded as expense $2.2 million of fees based on net profits.
 
The Utilities will apply for renewal of franchises in a timely manner prior to their respective expiration dates.
 
ITEM 1A.      RISK FACTORS

Risks related to NVE and the Utilities’ Results of Operations

Economic conditions could negatively impact our business.

Our operations are affected by local, national and global economic conditions.  Moreover, the growth of our business depends in part on continued customer growth and tourism demand in our service areas.  Over the last several years, adverse economic conditions have created uncertainty within the capital and commodity markets, including availability and cost of credit, inflation rates, monetary policy, unemployment rates and legislative and regulatory uncertainty.  A continued high rate of unemployment in Nevada may impact customers’ ability to pay their utility bills on a timely basis, increase customer bankruptcies, and lead to increased bad debt.  A lower level of economic activity, changes in discretionary spending, conservation efforts by our customers, and decreased tourism activity in our service areas have resulted in a decline in energy consumption, which has and may continue to affect our future growth. 

Our operating results will likely fluctuate on a seasonal and quarterly basis.

Electric power generation is generally a seasonal business.  In many parts of the country, including our service areas, demand for power peaks during the hot summer months, with market prices also peaking at that time.  As a result, our operating results in the future will likely fluctuate substantially on a seasonal basis.  In addition, we have historically sold less power, and consequently earned less income, when weather conditions in our service areas are milder.  Unusually mild weather in the future could diminish our results of operations and harm our financial condition.

Changes in consumer preferences, continuation of current economic conditions both nationally and globally, war, and the threat of terrorism or pandemics may harm our future growth and operating results.

Changes in consumer preferences or discretionary consumer spending in the Las Vegas portion of our service area could continue to harm our business.  We cannot predict the extent to which the current local economic environment or global economic environment, future terrorist and war activities, or pandemics, in the U.S. and elsewhere may affect us, directly or indirectly.  An extended period of reduced discretionary spending and/or disruptions or declines in airline and other travel and business conventions could significantly harm the businesses in and the continued growth of the Las Vegas portion of our service area, which could harm our business and results of operations.  

Our business operations could be adversely affected by cyber attacks or security breaches.

The Utilities are subject to cyber-security risks primarily related to breaches of security pertaining to sensitive customer, employee and vendor information maintained by the Utilities in the normal course of business, as well as breaches of their supervisory
 
 
 
 
control and data acquisition systems and other computer-based systems and networks used in the operation of their businesses.  A loss of confidential or proprietary data or security breaches of other computer systems or networks could adversely affect the Utilities’ reputation, diminish customer confidence, adversely affect the Utilities’ ability to manage facilities, networks, systems, programs and data efficiently or effectively, disrupt operations, and subject the Utilities to possible financial liability, any of which could have a material adverse effect on our financial condition and results of operations.  While the Utilities have procured insurance and have implemented protective measures designed to deter cyber attacks and security breaches and to mitigate their effects, there can be no assurance that such protective measures will be completely effective in protecting the Utilities from a cyber attack or security breach or the effects thereof or that insurance will be sufficient to compensate third parties from damages that result from cyber attacks or security breaches.
 
The Utilities could be subject to penalties if they violate mandatory NERC reliability standards.

The Energy Policy Act of 2005 amended the Federal Power Act to, among other matters, provide for mandatory reliability standards designed to assure the reliable operation of the bulk power system.  NERC established, and FERC approved, reliability standards that impose certain operating, planning and cyber-security requirements applicable to the Utilities.  The Utilities have been, and will continue to be, subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber-security assets) subject to NERC cyber-security standards that are designated as “critical assets.”  If the Utilities are found to be in violation of NERC’s mandatory reliability standards, the Utilities could be subject to civil fines imposed by the enforcement entities, which could have a material adverse effect on our results of operations, cash flows and financial condition.
 
Construction projects that we engage in are subject to a number of risks inherent in such projects, which could have adverse effects on our results of operations.

The nature of our business requires us to engage in significant construction projects from time to time, and each such construction project is subject to usual construction risks which could adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the ability to obtain or the cost of labor or materials; the ability of the contractors to perform under their contracts; equipment, engineering and design failure;  strikes; adverse weather conditions; the ability to obtain necessary operating permits in a timely manner; legal challenges; disputes with third parties; changes in applicable law or regulations; adverse interpretation or enforcement of permit conditions, laws and regulations by courts or the permitting agencies; other governmental actions; and events in the global economy. If we are unable to complete the development or construction of any construction project or decide to delay or cancel construction, we may not be able to recover our investment in the project and may incur substantial cancellation payments under equipment and construction contracts. Even if a construction project is completed, the total costs may be higher than estimated and/or higher than amounts approved by our regulators, and there is no guarantee that we will be allowed to recover these costs in rates. In addition, construction delays can result in the delay of revenues and, therefore, could affect our results of operations.

The ownership and operation of certain power generation and transmission lines on Indian lands could result in uncertainty related to continued leases, easements and rights-of-way, which could have a significant impact on our business.

Certain portions of the Utilities’ generating facilities and transmission lines that carry power from these facilities are located on Indian lands pursuant to leases, easements or other rights-of-way that are effective for specified periods. The Utilities are currently unable to predict the final outcome of discussions with the appropriate Indian tribes and approval by their respective governing bodies with respect to renewals of these leases, easements and rights-of-way.

Risks related to NVE and the Utilities’ Regulatory Proceedings

If the Utilities do not receive favorable rulings in their future GRCs or other regulatory filings, including energy efficiency recovery programs, such events may have a significant adverse effect on our financial condition, cash flows and future results of operations.

The Utilities’ revenues and earnings are subject to change as a result of regulatory proceedings known as GRCs, which the Utilities file with the PUCN approximately every three years.  In the Utilities’ GRCs, the PUCN establishes, among other things, their recoverable rate base, their ROE, overall ROR, depreciation rates and their cost of capital.

For a discussion of NPC’s and SPPC’s recent GRCs, see Note 3, Regulatory Actions, of the Notes to Financial Statements.

We cannot predict what the PUCN will direct in their orders on the Utilities’ future GRCs or other regulatory filings, including energy efficiency recovery programs.  Inadequate rates may have a significant adverse effect on the Utilities’ financial condition and future results of operations and may cause downgrades of their securities by the rating agencies and make it
 
 
 
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significantly more difficult or expensive to finance operations and construction projects and to buy fuel, natural gas and purchased power from third parties.

If the Utilities do not receive favorable rulings in the deferred energy applications that they file with the PUCN and they are unable to recover their deferred purchased power, natural gas and fuel costs, including changes in prices due to suspension of hedging programs, they will experience an adverse impact on cash flow and earnings.  Any significant disallowance of deferred energy charges in the future could materially adversely affect their cash flow, financial condition and liquidity.

Under Nevada law, purchased power, natural gas and fuel costs in excess of those included in base rates are deferred as an asset on the Utilities’ balance sheets and are not shown as an expense until recovered from their retail customers.  The Utilities are required to file DEAA applications with the PUCN at least once every twelve months so that the PUCN may verify the prudence of the energy costs.  Nevada law also requires the PUCN to act on these cases within a specified time period.  Any of these costs determined by the PUCN to have been imprudently incurred cannot be recovered from the Utilities’ customers.  

For a discussion of NPC’s and SPPC’s recent and pending deferred energy rate cases, see Note 3, Regulatory Actions, of the Notes to Financial Statements.

Material disallowances of deferred energy costs or inadequate BTERs would have a significant adverse effect on the Utilities’ financial condition and future results of operations, could cause downgrades of NVE’s and the Utilities’ securities by the rating agencies and could make it more difficult or expensive to finance operations and construction projects and buy fuel, natural gas and purchased power from third parties.
 
The Utilities purchase a portion of the power that they sell to their customers from power suppliers.  If the Utilities’ and/or their power suppliers’ credit ratings are downgraded, the Utilities may experience difficulty entering into new power supply contracts, and to the extent that they must rely on the spot market, they may experience difficulty obtaining such power from suppliers in the spot market in light of their financial condition, or the financial condition of their power suppliers.  In addition, if the Utilities experience unexpected failures or outages in their generation facilities, they may need to purchase a greater portion of the power they provide to their customers.  If access to liquidity is limited to obtain their power requirements, particularly for NPC at the onset of the summer months, and the Utilities are unable to obtain power through other means, their business, operations and financial condition will be materially adversely affected.

 If the Utilities cannot maintain the required level of renewable energy or procure sufficient solar energy to meet Nevada’s increasing Portfolio Standard, the PUCN may, among other things, impose an administrative fine for noncompliance.

Nevada law sets forth the Portfolio Standard requiring providers of electric service to acquire, generate or save from renewable energy systems or energy efficiency measures a specific percentage of its total retail sales from renewable energy sources or efficiency measures, which increases over time.  The standard also includes a specific requirement for solar energy that must be met on an annual basis by both Utilities.  The required amount of renewable energy and available supply can fluctuate widely based on multiple factors, including customer energy use, changes in law or regulation, renewable resource availability, and the financial stability of renewable counter parties, making the ability to anticipate future renewable energy needs and supplies difficult.  In the event the Utilities do not fully meet the standards in a given year, if the PUCN does not exempt them, they will be required to make up the PEC deficiency in subsequent years and may be subject to a financial penalty.

In 2011, the Utilities were required to obtain an amount of PECs equivalent to 15% of their total retail energy from renewables.  The Portfolio Standard remains at 15% for 2012, increases to 18% for 2013 and 2014, and reaches 20% in 2015, after which it increases again to 22% for the years 2020 through 2024, and to 25% for 2025 and beyond.  Moreover, not less than 5% of the total Portfolio Standard must be met from solar resources until 2016, when a minimum of 6% must be solar.  In the event the Utilities do not fully meet the standard in a given year, if the PUCN does not exempt them, they will be required to make up the PEC deficiency in subsequent years.

Due to periodic increases in the Portfolio Standard and increasing retail sales, the Utilities must acquire increasing amounts of renewable energy.  Since most of the Utilities’ renewable energy requirement is met by deliveries from third party suppliers, the Utilities’ success in meeting the increasing Portfolio Standard remains largely dependent on the ability of those third parties to meet minimum contractual obligations over the duration of the contract.   Similarly, self-owned generation and expected contributions from qualified conservation and energy efficiency measures would need to deliver and be certified by the PUCN as forecasted in each forecast year.  In 2011, the PUCN issued an order certifying that both Utilities had met the Portfolio Standard (and the solar requirement) and that NPC had eliminated any previous deficiency from 2010.  While both Utilities were successful in 2011 with respect to the Portfolio Standard, the intermittent and variable nature of the renewable portfolio, together with the increasing required renewable percentage, means that future years may still be subject to uncertainty around the Utilities’ ability to comply with the Portfolio Standard.
 
 

 
The Utilities’ ability to access the capital markets is dependent on their ability to obtain regulatory approval to do so.

The Utilities will need to continue to support capital expenditures and to refinance maturing debt through external financing.  The Utilities must obtain regulatory approval in Nevada in order to borrow money or to issue securities and are therefore dependent on the PUCN to issue favorable orders in a timely manner to permit them to finance their operations, construction and acquisition costs and to purchase power and fuel necessary to serve their customers.  As of December 31, 2011, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725 million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion. As of December 31, 2011, SPPC has financing authority from the PUCN for the period ending December 31, 2012, consisting of authority to (1) issue additional long-term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million.  However, we cannot assure you that in the future the PUCN will issue such favorable orders or that such favorable orders will be issued on a timely basis.

Risks related to NVE and the Utilities’ Environmental Matters

If Federal and/or State requirements are imposed on the Utilities mandating further emission reductions, including greenhouse gases and other pollutants, or if national ambient air quality standards are modified, such requirements could make some electric generating units uneconomical to maintain or operate.

Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses.  Certain congressional leaders, environmental advocacy groups and regulatory agencies in the U.S. have also been focusing considerable attention on emissions from power generation facilities and their potential role in climate change and/or regional air quality.  Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level that are aimed at the reduction of fossil plant emissions, as well as modification of the NAAQS for ozone and other pollutants. We cannot predict the outcome of pending or future legislative and rulemaking proposals.  Future changes in environmental laws or regulations governing emissions reductions could make certain electric generating units, especially those utilizing coal for fuel, uneconomical to construct, maintain or operate or could require design changes or the adoption of new technologies that could significantly increase costs or delay in-service dates.  In addition, any legal obligation that would require the Utilities to substantially reduce their emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation or regulation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.

The Utilities are subject to numerous environmental laws and regulations that may increase our cost of operations, impact or limit our business plans, expose us to environmental liabilities, or make some electric generating units uneconomical to maintain or operate.

The Utilities are subject to extensive federal, state and local laws and regulations relating to environmental protection.  These laws and regulations can result in increased capital, construction, operating, and other costs.  These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals, and may be enforced by both public officials and private individuals.  We cannot predict the outcome or effect of any action or litigation that may arise from applicable environmental regulations.

In addition, either of the Utilities may be identified as a responsible party for environmental cleanup by environmental agencies or regulatory bodies.  We cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs.  There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liabilities on all potentially responsible parties.  Environmental regulations may also require us to install pollution control equipment at, or perform environmental remediation on, our facilities.

Existing environmental regulations regarding air emissions (such as NOX, SO2 or mercury emissions), water quality, coal combustion by products and other pollutants may be revised or new climate change laws or regulations may be adopted or become applicable to us.  Revised or additional laws or regulations, which may result in increased compliance costs, including the adoption of new technologies or additional operating restrictions, could have a material adverse effect on our financial condition and results of operations particularly if those costs are not fully recoverable from our customers.
 
        Furthermore, we may not be able to obtain or maintain all environmental regulatory approvals necessary to our business.  If there is a delay in obtaining any required environmental regulatory approval or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be delayed, halted or subjected to additional costs.
 
 

 
Risks related to NVE and the Utilities’ Liquidity and Capital Resources

Lower than expected investment returns on pension and other postretirement plan assets and other factors may increase NVE’s pension and other postretirement plan liability and funding requirements.

            Substantially all of NVE employees are covered by a single employer defined benefit pension and other postretirement plan.  At present, the pension and other postretirement plan is underfunded in that the projected benefit obligations exceed the aggregate fair value of plan assets.  The funded status of the plan can be affected by contributions to plan assets, plan design, investment returns on plan assets, discount rates, mortality rates of plan participants, pension reform legislation and a number of other factors.  There can be no assurance that the value of NVE’s pension and other postretirement plan assets will be sufficient to cover future liabilities.  Although NVE has made significant contributions to its pension and other postretirement plan in recent years, it is possible that NVE could incur a significant pension and other postretirement liability adjustment, or could be required to make significant additional cash contributions to its plan, which would reduce the cash available for operating activities, and have a material impact on earnings.  Refer to Note 11, Retirement Plan and Post-Retirement Benefits, of the Notes to Financial Statements.

As a result of the suspension of the Utilities’ hedging programs, the Utilities are subject to fuel and wholesale electricity pricing risks, which could result in unanticipated liabilities and cash flow requirements or increased volatility in our earnings, and to related credit and liquidity risks.

Beginning in October 2009, the Utilities suspended their hedging programs; however, prior to the suspension, it was the general policy of the Utilities to purchase hedges three seasons ahead.  As a result certain hedges entered into prior to the suspension in October 2009, did not terminate until 2011.  As of November 2011, all hedging transactions have expired or terminated and the Utilities remain unhedged.  If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.  As such, fluctuating commodity prices could have a material adverse effect on their cash flows and their ability to operate and, consequently, on our financial condition.
 
The Utilities’ business and operations are subject to changes in purchased power prices and fuel costs that may cause increases in the amounts they must pay for power supplies on the wholesale market and the cost of producing power in their generation plants.  Prices for electricity, fuel and natural gas may fluctuate substantially over relatively short periods of time and expose the Utilities to significant commodity price risks.  
 
Increasing energy commodity prices, particularly with respect to natural gas, have a significant effect on our short-term liquidity.  Although the Utilities are entitled to recover their prudently incurred power, natural gas and fuel costs through deferred energy rate case filings with the PUCN, if current commodity prices increase, the Utilities’ deferred energy balances will increase, which will negatively affect our cash flow and liquidity until such costs are recovered from customers.

The Utilities are also subject to credit risk for losses that they incur as a result of non-performance by counterparties of their contractual obligations to deliver fuel, purchased power, natural gas (for resale) or settlement payments.  The Utilities often extend credit to counterparties and customers and they are exposed to the risk that they may not be able to collect amounts owed to them.  Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it, and also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty.  Should a counterparty, customer or supplier fail to perform, the Utilities may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment.

The Utilities are also subject to liquidity risk resulting from the exposure that their counterparties perceive with respect to the possible non-performance by the Utilities of their physical and financial obligations under their energy, fuel and natural gas contracts.  These counterparties may under certain circumstances, pursuant to the Utilities’ agreements with them, seek assurances of performance from the Utilities in the form of letters of credit, prepayment or cash deposits, or reduce availability under the Utilities’ revolving credit facilities for negative mark-to-market positions.  In periods of price volatility, the Utilities’ exposure levels can change significantly, which could have a significant negative impact on our liquidity and earnings.  In the event the Utilities’ credit ratings are downgraded below investment grade, the maximum amount of collateral the Utilities would be required to post is approximately $64.7 million.  Additionally, the Utilities shall reduce their availability under their revolving credit facilities for negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities.
 
 

 
If NVE is precluded from receiving dividends from the Utilities, its financial condition, and its ability to meet its debt service obligations, pay dividends and make capital contributions to its subsidiaries, will be materially adversely affected.

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE.  Since NPC and SPPC are public utilities, they are subject to regulation by the PUCN, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.

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

We cannot assure investors that future dividend payments on our Common Stock will be made or, if made, in what amounts they may be paid.

Dividends are considered periodically by NVE’s BOD and are subject to factors that ordinarily affect dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and dividend restrictions in NVE’s and the Utilities’ financing agreements.  The BOD will continue to review these factors on a periodic basis to determine if and when it would be prudent to declare a dividend on NVE’s Common Stock; however, there is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid in the same amount or with the same frequency as in the past.
 
NVE’s indebtedness is effectively subordinated to the liabilities of its subsidiaries, particularly NPC and SPPC.  NVE and the Utilities have the ability to issue a significant amount of additional indebtedness under the terms of their various financing agreements.

Because NVE is a holding company, its indebtedness is effectively subordinated to the Utilities’ existing indebtedness and other future liabilities, including claims by the Utilities’ trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders.  NVE conducts substantially all of its operations through its subsidiaries, and thus NVE’s ability to meet its obligations under its indebtedness and to pay any dividends on its common stock will be dependent on the earnings and cash flows of those subsidiaries and the ability of those subsidiaries to pay dividends or to advance or repay funds to NVE.  As of December 31, 2011, the Utilities had approximately $4.6 billion of debt outstanding.  The terms of NVE’s indebtedness restrict the amount of additional indebtedness that NVE and the Utilities may issue.  Based on NVE’s December 31, 2011 financial statements, NVE’s indebtedness restrictions would allow NVE and the Utilities to issue up to approximately $2.8 billion of additional indebtedness in the aggregate, plus indebtedness that is specifically permitted under the terms of NVE’s indebtedness.  In addition, NPC and SPPC are subject to restrictions under the terms of their various financing agreements on their ability to issue additional indebtedness.

ITEM 1B.                      UNRESOLVED STAFF COMMENTS
  
None.
 
 
 
ITEM 2.                      PROPERTIES

Substantially all of NPC’s and SPPC’s property in Nevada is subject to the lien of the General and Refunding Mortgage Indentures dated as of May 1, 2001, between NPC and SPPC, respectively, and The Bank of New York Mellon Trust Company, N.A., as trustee, as amended and supplemented.

NVE’s total summer MW capacity and units were 5,862 MWs and 63 units, respectively.  The following is a list of NPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2012 net capacity (MW), and the years that the units were installed.

NPC

   
 
 
 
 
Number of
 
Summer MW
 
Commercial
Plant Name
 
Type
 
Fuel
 
Units
 
Capacity
 
Operation Year
   
 
 
 
 
 
 
 
 
 
Clark Generating Station
 
Combined Cycle
 
Gas
 
6
 
430
 
1979, 1979, 1980, 1982,
   
 
 
 
 
 
 
 
 
1993, 1994
   
Gas
 
Gas
 
1
 
54
 
1973
   
Peakers
 
Gas
 
12
 
619
 
2008
Sunrise(1)
 
Steam
 
Gas
 
-
 
-
 
1964
   
Gas
 
Gas
 
-
 
-
 
1974
Harry Allen Generating Station
 
Combined Cycle
 
Gas
 
3
 
484
 
2011
   
Gas
 
Gas
 
2
 
144
 
1995, 2006
Lenzie Generating Station
 
Combined Cycle
 
Gas
 
6
 
1102
 
2006
Silverhawk Generating Station(2)
 
Combined Cycle
 
Gas
 
3
 
395
 
2004
Higgins Generating Station
 
Combined Cycle
 
Gas
 
3
 
530
 
2004
Mohave Generating Station(3)
 
Steam
 
Coal
 
-
 
-
 
1971
Navajo Generating Station(4)
 
Steam
 
Coal
 
3
 
255
 
1974, 1975, 1976
Reid Gardner Generating Station(5)
 
Steam
 
Coal
 
4
 
325
 
1965, 1968, 1976, 1983
Goodsprings
 
Waste Heat
 
 
 
1
 
5
 
2010
Total
 
 
 
 
 
44
 
4,343
 
 
 
 
(1)
Sunrise Station Units 1 & 2 were retired with PUCN approval on 12/31/2011.
(2)
Silverhawk Generating Station is jointly owned by NPC and SNWA, 75% and 25%, respectively.
(3)
Per a 1999 Consent Decree, Mohave Generating Station ceased operation on December 31, 2005.  Prior to the shut down, the total summer net capacity of the Mohave Generating Station was 1,580 MW.  Southern California Edison is the operating agent and NPC has a 14% interest in the Mohave Generating Station.
(4)
NPC has an 11.3% interest in the Navajo Generating Station.  The total capacity of the Navajo Generating Station is 2,250 MW.  Salt River is the operator (21.7% interest).
(5)
Reid Gardner Generating Station Unit No. 4 is co-owned by the CDWR (67.8%) and NPC (32.2%); NPC is the operating agent.  NPC is entitled to 24 MW of base load capacity and 233 MW of peaking capacity from that Unit, subject to the following limitations: 1,500 hours/year, 300 hours/month, and 8 hours/day.  The total summer net capacity of the Unit, subject to heat input limitation, is 257 MW.  Reid Gardner Generating Station Units 1, 2, and 3, subject to heat input limitations, have a combined net capacity of 300 MW.  The Reid Gardner Generating Station summer capacity is 557 MW.  The agreement with CDWR terminates in 2013, at which time NPC assumes 100% ownership.
 
    The following is a list of SPPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2012 net capacity (MW), and the years that the units were installed.
 
 

 
SPPC

 
 
 
 
 
 
Number of
 
Summer MW
 
Commercial
Plant Name
 
Type
 
Fuel
 
Units
 
Capacity
 
Operation Year
 
 
 
 
 
 
 
 
 
 
 
Ft. Churchill Generating Station
 
Steam
 
Gas/Oil
 
2
 
226
 
1968, 1971
Tracy Generating Station
 
Steam
 
Gas/Oil
 
3
 
244
 
1963, 1965, 1974
Tracy Generating Station 4&5
 
Combined Cycle
 
Gas
 
2
 
104
 
1996, 1996
Tracy Generating Station
 
Combined Cycle
 
Gas
 
3
 
541
 
2008
Clark Mtn. CT's
 
Gas
 
Gas/Oil
 
2
 
132
 
1994, 1994
Valmy Generating Station(1)
 
Steam
 
Coal
 
2
 
261
 
1981, 1985
Other
 
Diesel
 
Oil
 
5
 
11
 
1960-1970
Total
 
 
 
 
 
19
 
1,519
 
 

  (1)
Valmy Generating Station is co-owned by Idaho Power Company (50%) and SPPC (50%); SPPC is the operator.  Valmy Generating Station has a total net capacity of 522 MW.

ITEM 3.                      LEGAL PROCEEDINGS

NPC and SPPC

   Western United States Energy Crisis Proceedings before the FERC

      FERC 206 complaints

In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States Energy Crisis.  The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.

Over the course of the last ten years, the Utilities litigated and settled the termination claims with the various power suppliers. The Utilities had previously negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., Calpine Energy Services and Enron.  The Utilities completed bilateral settlement discussions with Allegheny Energy Supply Company (Allegheny), American Electric Power Service Corporation (AEP) and BP Energy in 2009 and 2010.  The Utilities, together with other interested parties including the BCP, settled and resolved all claims against BP Energy, AEP and Allegheny, each for an immaterial amount in return for a release of all claims by the Utilities and BCP.  The settlement agreement with Allegheny received final approval by the FERC in January 2011.  With the final approval of the Allegheny Settlement by FERC, all of the Utilities’ FERC 206 complaints are settled and resolved.

Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on their financial positions or results of operations.  See Note 13, Commitments and Contingencies, in the Notes to Financial Statements for further discussion of other legal matters.

ITEM 4.                      MINE SAFETY DISCLOSURES

Not applicable.


PART II

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (NVE)

NVE’s Common Stock is traded on the New York Stock Exchange (symbol NVE).  Dividends paid per share and high and low sale prices of the Common Stock as reported for 2011 and 2010 are as follows:

 
 
 
Dividends declared per share
 
 
2011
 
 
2010
 
 
 
2011
 
 
2010
 
 
High
 
 
Low
 
 
High
 
 
Low
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
First Quarter
$
 0.12