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, 2008
             
Commission File
 
Registrant, Address of Principal Executive Offices and Telephone
 
I.R.S. Employer
 
State of
Number
 
Number
 
Identification Number
 
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
7.803% Senior Notes Due 2012
 
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. Yesþ   Noo
     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.   þ
     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 definition 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, 2008: $ 2,975,041,902
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 20, 2009:   234,322,462 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 April 30, 2009, 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.


1


NV ENERGY, INC.
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
2008 ANNUAL REPORT ON FORM 10-K

CONTENTS

 Acronyms and Terms  
   
PART I
 
 
     ITEM 1.
   BUSINESS...............................................................................................................................................................................................................................................................................
5
     NV Energy, Inc............................................................................................................................................................................................................................................................................................
5
     Nevada Power Company..........................................................................................................................................................................................................................................................................
7
     Sierra Pacific Power Company...............................................................................................................................................................................................................................................................
16
     Other Subsidiaries of NV Energy, Inc....................................................................................................................................................................................................................................................
25
     ITEM 1A.
  RISK FACTORS......................................................................................................................................................................................................................................................................
27
     ITEM 1B.
  UNRESOLVED STAFF COMMENTS..................................................................................................................................................................................................................................
32
     ITEM 2.
   PROPERTIES..........................................................................................................................................................................................................................................................................
32
     ITEM 3.
   LEGAL PROCEEDINGS.........................................................................................................................................................................................................................................................
33
     ITEM 4.
   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.........................................................................................................................................................................
34
     Executive Officers........................................................................................................................................................................................................................................................................................
34
 
PART II
 
 
     ITEM 5.
   MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (NVE)................
36
     ITEM 6.
   SELECTED FINANCIAL DATA..........................................................................................................................................................................................................................................
37
     ITEM 7.
   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS...................................................................................
40
     Executive Overview....................................................................................................................................................................................................................................................................................
42
     NV Energy, Inc............................................................................................................................................................................................................................................................................
52
         RESULTS OF OPERATIONS.................................................................................................................................................................................................................................................................
52
         ANALYSIS OF CASH FLOWS.............................................................................................................................................................................................................................................................
53
         LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED).............................................................................................................................................................................................
53
     Energy Supply (Utilities)..........................................................................................................................................................................................................................................................................
60
     Nevada Power Company..........................................................................................................................................................................................................................................................................
63
         RESULTS OF OPERATIONS................................................................................................................................................................................................................................................................
63
         ANALYSIS OF CASH FLOWS.............................................................................................................................................................................................................................................................
68
         LIQUIDITY AND CAPITAL RESOURCES.........................................................................................................................................................................................................................................
69
     Sierra Pacific Power Company................................................................................................................................................................................................................................................................
73
         RESULTS OF OPERATIONS.................................................................................................................................................................................................................................................................
73
         ANALYSIS OF CASH FLOWS.............................................................................................................................................................................................................................................................
80
         LIQUIDITY AND CAPITAL RESOURCES.........................................................................................................................................................................................................................................
81
     Regulatory Proceedings (Utilities).........................................................................................................................................................................................................................................................
85
     ITEM 7A.
   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...................................................................................................................................................
86
     ITEM 8.
   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...................................................................................................................................................................................
88
     ITEM 9.
   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE................................................................................
161
     ITEM 9A.
   CONTROLS AND PROCEDURES.......................................................................................................................................................................................................................................
161
     ITEM 9B.
   OTHER INFORMATION.....................................................................................................................................................................................................................................................
163
 
PART III
 
 
     ITEM 10.
   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT.....................................................................................................................
163
     ITEM 11.
   EXECUTIVE COMPENSATION..........................................................................................................................................................................................................................................
163
     ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.....................................................
163
     ITEM 13.
   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................................................................................................................................................................................
163
     ITEM 14.
   PRINCIPAL ACCOUNTING FEES AND SERVICES........................................................................................................................................................................................................
163
 
PART IV
 
 
     ITEM 15.
   EXHIBITS, FINANCIAL STATEMENT SCHEDULES.....................................................................................................................................................................................................
164
SIGNATURES...................................................................................................................................................................................................................................................................................................
165


2



(The following common acronyms and terms are found in multiple locations within the document)
     
Acronyms/Terms
 
Meaning
     
AFUDC
 
Allowance for Funds Used During Construction or Allowance for Borrowed Funds Used During Construction
AOC
 
Administrative Order on Consent
BCP
 
Bureau of Consumer Protection
BOD   Board of Directors
BTER
 
Base Tariff Energy Rate
BTGR
 
Base Tariff General Rate
CDWR
 
California Department of Water Resources
CIAC
 
Contributions in Aid of Construction
Clark Generating Station
 
William Clark Generating Station
CPUC
 
California Public Utilities Commission
CSA
 
Coal Supply Agreement
CWIP
 
Construction Work-In-Progress
DBRS
 
Dominion Bond Rating Service
DEAA
 
Deferred Energy Accounting Adjustment
DOS
 
Distribution Only Service
DSM
 
Demand Side Management
Dth
 
Decatherms
e-three
 
Sierra Energy Company d/b/a e-three
EEC
 
Ely Energy Center
EN-ti line       250 mile 500 kV transmission line
EPA
 
Environmental Protection Agency
EPS
 
Earnings Per Share
EROC
 
Enterprise Risk Oversight Committee
ESP
 
Energy Supply Plan
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
FIN 46 (R)
 
Interpretation No. 46, “Consolidation of Variable Interest Entities”
FIN 47
 
Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”
FIN 48
 
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”
Fitch
 
Fitch Ratings, Ltd.
FSP   FASB Staff Position
FSP 132(R)-1   FASB Staff Position No 132(R)-1, "Employers Disclosures about Pensions and Other Postretirement Benefits"
FSP 157-3   FASB Staff Position No. 157-3, "Determining the Fair Value of Financial Asset When the Market for that Asset is Not Active"
GAAP
 
Accounting Principles Generally Accepted in the United States
GRC
 
General Rate Case
IBEW
 
International Brotherhood of Electrical Workers
Higgins Generating Station
 
Walter M. Higgins, III Generating Station
IRP
 
Integrated Resource Plan
kV
 
Kilovolt
kWh
 
Kilowatt Hour
Lenzie Generating Station
 
Chuck Lenzie Generating Station
LDC
 
Local Distributing Company
LOS
 
Lands of Sierra, Inc.
Moody’s
 
Moody’s Investors Services, Inc.
MW
 
Megawatt
MWh
 
Megawatt hour
NDEP
 
Nevada Division of Environmental Protection
NEICO
 
Nevada Electrical Investment Company
NERC
 
North American Electric Reliability Corporation
NOV
 
Notice of Violation
NPC
 
Nevada Power Company d/b/a NV Energy
NVE   NV Energy, Inc.
OATT
 
Open Access Transmission Tariff
PEC
 
Portfolio Energy Credit
Portfolio Standard
 
Renewable Energy Portfolio Standard
 
 
 
 
 
PPC   Piñon Pine Corporation
PPIC   Piñon Pine Investment Company
PUCN
 
Public Utilities Commission of Nevada
QFs
 
Qualifying Facilities
RFP
 
Request for Proposal
ROE
 
Return on Equity
ROR
 
Rate of Return
S&P
 
Standard and Poor’s
Salt River
 
Salt River Project
SEC
 
Securities and Exchange Commission
SFAS
 
Statement of Financial Accounting Standards
SFAS 13   Statement of Financial Accounting Standards No. 13, "Accounting for Leases"
SFAS 71
 
Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 87   Statement of Financial Accounting Standards No. 87, "Employer's Accounting for Pensions"
SFAS 90
  Statement of Financial Accounting Standards No. 90, "Accounting for Abandonments and Disallowances of Plant Costs"
SFAS 106
  Statement of Financial Accounting Standards No. 106, "Employers Accounting for Postretirement Benefits Other Than Pensions"
SFAS 109   Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes"
SFAS 123R
 
Statement of Financial Accounting Standards No. 123R, “Share Based Payments”
SFAS 128   Statement of Financial Accounting Standards No. 128, "Earnings Per Share"
SFAS 131
  Statement of Financial Accounting Standards No. 131, "Disclosure About Segments of an Enterprise and Related Information"
SFAS 133
 
Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 138
  Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133"
SFAS 143
 
Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
SFAS 144
  Statement of Financial Accounting Standards No. 144, "Accounting for the Disposal or Impairment of Long-Lived Assets"
SFAS 149
  Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities"
SFAS 155
  Statement of Financial Accounting Standards No. 155, "Accounting for Certain Hybrid Financial Instruments - An Amendment of FASB Statements No. 133 and 140"
SFAS 157
 
Statement of Financial Accounting Standards No. 157, “Fair Value Measurement”
SFAS 158
 
Statement of Financial Accounting Standards No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement  Plans”
SFAS 159
 
Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”
SFAS 161
 
Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activity”
SGHC
 
Sierra Gas Holding Company
SNWA
 
Southern Nevada Water Authority
SOP 96-1   Statement of Position, "Environmental Remediation Liabilities"
SPC
 
Sierra Pacific Communications
SPE
 
Sierra Pacific Energy Company
SPPC
 
Sierra Pacific Power Company d/b/a NV Energy
SPR
 
Sierra Pacific Resources
SRSG
 
Southwest Reserve Sharing Group
SWDC
 
Sierra Water Development Company
TGPC
 
Tuscarora Gas Pipeline Company
TGTC
 
Tuscarora Gas Transmission Company
TMWA
 
Truckee Meadows Water Authority
Tracy Generating Station
 
Frank A. Tracy Generating Station
U.S.   United States of America
Valmy Generating Station
 
North Valmy Generating Station
WECC
 
Western Electricity Coordinating Council
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


NV ENERGY, INC.

NV Energy, Inc., formerly Sierra Pacific Resources, 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 6226 West Sahara Avenue, Las Vegas, Nevada 89146.

NVE has six primary, wholly-owned subsidiaries: Nevada Power Company d/b/a NV Energy, Sierra Pacific Power Company d/b/a NV Energy, Sierra Pacific Communications, Sierra Pacific Energy Company, 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”.  In 2008, Sierra Pacific Resources changed its name to NV Energy, Inc.  In addition, NPC and SPPC announced they will do business under the name NV Energy.  The name change unifies under a single brand a company that serves Nevada's energy needs from north to south.
 
The Utilities operate three business segments, as defined by SFAS 131: NPC electric; SPPC electric; and SPPC natural gas.  Electric service is provided to Las Vegas and surrounding Clark County, and to northern Nevada and the Lake Tahoe area of California.  Natural gas service is provided 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 and SPPC service territories are as follows:

NVE Service Area


5

 
The Utilities provide electric and natural gas services to a diverse mix of over one million residential, commercial, industrial and public sector customers.  Major industries served include gaming/recreation, mining, warehousing/manufacturing, offices, health care, education, military bases and other 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.

Beginning in 2007, the Utilities embarked on a three part energy supply strategy to manage resources against our load by conserving energy, investing in renewable resources and building generation in an effort to reduce our reliance on purchased power.

Energy Efficiency and Conservation Programs

NPC and SPPC have designed a portfolio of cost effective DSM programs that allow every customer to take advantage of savings from energy efficiency measures.  DSM programs are marketed across all segments of customer classes (residential, commercial, public, and low income).

The Portfolio Standard, discussed below, allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard.  A PEC is created for each kWh of energy conserved by qualified energy efficiency programs, or generated by renewable energy systems.  Energy saved during peak demand hours earns double the PEC's.  After the DSM percentage allowance is fully utilized, NPC’s and SPPC’s strategy is to continue to implement cost-effective DSM programs.

In 2008, the Utilities invested $55 million towards energy efficiency and conservation programs.  The Utilities are planning to invest between $45 million and $60 million in 2009.  The final amount will be determined by numerous factors, such as the economy, the impact of the federal government stimulus legislation, the performance of existing and new programs and many other factors.  The PUCN has approved investments in efficiency and qualified conservation programs of approximately $140 million, which will be deferred as a regulatory asset, subject to prudency review by the PUCN.  Given the Utilities’ 2008 investment level, management believes that the Utilities are in a position to achieve the maximum allowable 25% in 2008 to meet renewable portfolio compliance.  This report will be filed with the PUCN in April 2009.

Purchase and Development of Renewable Resources

Nevada law sets forth the Portfolio Standard requiring providers of electric service to acquire, generate, or save a specific percentage of its total retail energy sales from renewable energy resources.  Renewables include biomass, geothermal, solar, waterpower and wind projects.  Pursuant to the Portfolio Standard, NPC and SPPC were required to obtain an amount of PEC’s equivalent to nine percent of their total retail energy sales from renewables for year 2008.  The Portfolio Standard increases by three percent to 12% in 2009 and by an additional three percent every other year until it reaches 20% in year 2015.  Moreover, not less than five percent of the total Portfolio Standard must be met from solar resources.  Compliance with the Portfolio Standard is measured in PEC's administered by the PUCN.  PEC's not needed to fulfill the Utilities’ compliance obligation (excess) are carried over for future years’ compliance; and, with PUCN approval, can be exchanged between the Utilities.

Nevada law requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard.  In the Utilities’ April 2008 Portfolio Standard Annual Report for Compliance Year 2007 (submitted to the PUCN jointly), the Utilities reported that with the PUCN approval of the transfer of SPPC’s excess non-solar PEC’s to NPC, the Utilities were able to comply with the non-solar Portfolio Standard.  However, due to the late commercial operation of solar facilities, the Utilities did not meet the solar portion of the Portfolio Standard.  The PUCN issued its order accepting the Utilities’ Portfolio Standard Annual Report for Compliance Year 2007.  In addition, as a result of the Utilities’ efforts to add solar resources, the PUCN granted an exemption to the Utilities for non-compliance with the solar requirement.

Generation

In 2003, the Utilities embarked on a strategy to build or acquire generating facilities to decrease their dependence on purchased power.  Since then, the Utilities have increased their summer net generating capacity by 100%.  Additionally, in 2007, NPC began construction of a 500 MW (nominally rated) natural gas fired combined cycle generator at the Harry Allen Generating Station, with an expected completion date in 2011.  The PUCN has currently approved approximately $130 million be spent towards the development of the EEC.  The EEC consists of two 750 MW coal generation units to be located near Ely, Nevada.  However, on February 9, 2009, NVE and the Utilities announced their intention to postpone plans to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade.  NVE and the Utilities still plan to proceed with the construction of the EN-ti  line, which will link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state, allowing for the transfer of energy, including renewable resources, between the Utilities.  The Utilities  and will seek approval from the PUCN to accelerate the development of the EN-ti line.

 
6

 
Despite the significant investment since 2003, the Utilities do not own sufficient generating facilities to meet peak demands.  As a result of this shortfall and forecasted market opportunities, NPC is forecasting to purchase approximately 23% of its total system energy needs from the wholesale market and SPPC is forecasting to purchase approximately 34% of its total system energy needs from the wholesale market for year 2009.  For the 2009 summer peak, the Utilities have secured 100% of their forecasted capacity needs.  The amount of power purchased by the Utilities varies from time to time depending on demand, the cost of purchased power compared with our cost of generation, and the availability of such power.  As a comparison, in 2008, NPC and SPPC purchased approximately 32.5% and 49.5%, respectively, of their energy needs.  Some purchased power contracts are indexed to natural gas prices.  Due to the relatively large seasonal gas and purchased power usage, the Utilities purchase power and hedge a portion of their total natural gas exposure as discussed further in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.

The Utilities continue to evaluate the resource needs of their service territory; however, they expect more moderate construction of generating units in the future.

As a result of expanded service territory growth, both Utilities have added transmission infrastructure.  The new transmission lines are discussed in NPC’s and SPPC’s respective Transmission sections below.

Nevada state law allows, with PUCN approval, commercial customers with an average annual load of one MW or more, to choose alternate energy suppliers.  In addition, some large customers may own and operate generation facilities to meet their own energy requirements.  In 2008, Newmont Mining Corporation, a large SPPC mining customer, began operations of a 203 MW facility.  Moreover, the City of Las Vegas has filed with the PUCN to exit NPC's system in regards to nine premises.  These matters are discussed further under Business and Competitive Environment, Competition, for NPC and SPPC below.

The FERC, PUCN and, in the case of the California service territory of SPPC, the CPUC regulate portions of the Utilities’ accounting practices and electricity and natural gas rates.  The FERC regulates the terms and prices of transmission services and sales of wholesale electricity.  The PUCN and CPUC have authority over general and energy rates charged to retail customers, the issuance of securities and transactions with affiliated parties.

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 issuers that file electronically 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, 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.

NEVADA POWER COMPANY

NPC is a Nevada corporation organized in 1921 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 6226 West Sahara Avenue, Las Vegas, Nevada 89146.

NEICO is a wholly-owned subsidiary of NPC.  NEICO is a 25% member of Northwind Aladdin, LLC, which operates the central energy plant at the Aladdin Resort and Casino in Las Vegas.  The other 75% of Northwind Aladdin, LLC is owned by Macquarie Infrastructure Company Trust.

Business and Competitive Environment

   Overview

NPC is a public utility that generates, transmits and distributes electric energy in southern Nevada.  At year-end 2008, NPC served approximately 827,000 customers in Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin, and adjoining areas, including Nellis Air Force Base and the Department of Energy’s Nevada Test Site in Nye County.
 
 
7

 
   Electric Operations

NPC is charged with meeting the growing electric energy needs of the residential population and expanding business and public sectors in Southern Nevada.  In addition to customer growth, demand and resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use.  NPC’s peak demand occurs in the summer.  Therefore, NPC’s revenues and associated expenses are not incurred or generated evenly throughout the year.
 
To serve its customer base, NPC generates electricity and purchases power in accordance with an ESP, as discussed in more detail later in this section and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.  In 2008 in a continued effort to reduce reliance on purchased power, NPC completed the construction of 619 MWs (nominally rated) peaking units at the Clark Generating Station.  Additionally, in October NPC completed the acquisition of the 598 MW (nominally rated) Higgins Generating Station.  Construction also continues on a 500 MW (nominally rated) unit at the Harry Allen Generating Station which is scheduled to be completed in 2011.

Nevada regulations require NPC to file GRCs every three years with the PUCN to adjust rates including cost of service and return on investment.  Nevada state regulations also require NPC to file annual DEAA applications to either recover or refund 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, NPC is required quarterly to file to reset BTERs, reflecting more recent fuel and purchased power costs.  Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.

The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting, and other matters in connection with NPC’s sale of electricity for resale and interstate transmission.  The FERC also has jurisdiction over the natural gas pipeline companies from which NPC buys transportation for natural gas.

   Competition

State law allows commercial customers with an average annual load of 1 MW or more to 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, the departure must not burden NPC 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 NPC.  Customers wishing to choose a new supplier must provide 180-day notice to NPC.  NPC would continue to provide transmission, distribution, metering, and billing services to such customers.  Management believes that those customers securing energy from new energy suppliers would reduce NPC’s need to purchase power from potentially volatile wholesale energy markets.  The City of Las Vegas has filed with the PUCN to exit NPC’s system in regards to nine premises.  The departure is not expected to materially affect NPC’s load requirements.
 
Sales

In 2008, NPC’s operating revenues were approximately $2.3 billion.  Summer peak loads are driven by air conditioning demand.  Winter peak loads are low relative to the summer peak.  NPC’s peak load increased at an average annual growth rate of 2.5% over the past five years, reaching 5,504 MW in July 2008.  NPC’s retail total electric MWh sales have increased at an average annual growth rate of 3.3% over the past five years; however, retail electric MWh sales declined slightly from 2007 to 2008, as discussed below.
 
 
8

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

   
MWh Sales (Billed and Unbilled)
 
   
2008
   
2007
   
2006
 
   
MWh
   
% of Total
   
MWh
   
% of Total
   
MWh
   
% of Total
 
                                     
Residential
    9,041,403       41.4 %     9,371,726       42.4 %     9,033,142       42.3 %
                                                 
Commercial & Industrial:
                                               
    Gaming/Recreation/Restaurants
    3,695,156       16.9 %     3,697,324       16.7 %     3,736,608       17.5 %
    All Other Retail
    8,644,314       39.5 %     8,551,874       38.7 %     8,049,753       37.7 %
Total Retail
    21,380,873       97.8 %     21,620,924       97.8 %     20,819,503       97.5 %
                                                 
Wholesale
    238,511       1.1 %     240,934       1.1 %     244,128       1.2 %
                                                 
Sales to Public Authorities
    231,647       1.1 %     252,119       1.1 %     281,369       1.3 %
                                                 
Total
    21,851,031       100.0 %     22,113,977       100.0 %     21,345,000       100.0 %

Total retail MWh sales decreased approximately 1.1% in 2008 from 2007, primarily due to a decrease in residential customer usage as a result of cooler summer weather and, to a lesser extent, changes in residential customer usage patterns.

Tourism and gaming remain southern Nevada’s leading industries and together comprise one of NPC’s largest classes of customers.  Management believes hotel room growth rate is one of the key indicators of southern Nevada’s economic health and leading indicators of overall system load growth.  The expected room growth rate for 2009 is 9.1% and 2.7% for 2010.  The significant increase in room growth for 2009 is primarily due to Project City Center, which is expected to add approximately 6,000 rooms to Las Vegas.  NPC’s average retail residential customer count increased by 0.8% in 2008 from 2007, although the rate of growth has decreased significantly from prior years as a result of economic conditions both regionally and nationally.

Nevada is ranked as the eighth fastest growing state in the nation by the U.S. Census Bureau for the twelve months ended June 30, 2008.  However, the southern Nevada economy has been adversely affected by the recession facing the United States and the global economy, resulting in an increase in unemployment to 9.1% compared to 5.6% in 2007, a decrease in hotel/motel occupancy of 11.9% from the 2007 level, and a decrease in new home sales to 9,780 in 2008 compared to 19,670 and 36,051 in 2007 and 2006, respectively.

Demand

Load and Resources Forecast

NPC’s integrated peak electric demand decreased from 5,866 MW in 2007 to 5,504 MW in 2008.  Variations in energy usage occur as a result of varying weather conditions, economic conditions, and other energy usage behaviors, such as conservation efforts.  This necessitates 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.

NPC plans to meet its customers’ needs through a combination of company-owned-generation and purchased power.  See the Generation section and Purchased Power section below for details of NPC’s generation and contracts for purchased power.  Remaining needs will be met through power purchases through RFPs or short term purchases.

9

 
    Below is a table summarizing the forecasted summer electric capacity requirement and resource needs of NPC (assuming no curtailment of supply or load, and normal weather conditions):

   
Forecasted Electric Capacity
 
   
Requirements and Resources (MW)
 
                               
   
2009
   
2010
   
2011
   
2012
   
2013
 
                               
Total requirements (1)
    6,611       6,657       6,724       6,915       6,946  
                                         
Resources:
                                       
Company-owned existing generation (2)
    4,234       4,234       4,180       4,180       4,175  
Company-owned new generation (3)
    -       -       489       489       489  
Contracts for power purchases
    2,431       2,231       2,237      
2,237
      2,275  
Total resources
    6,665       6,465       6,906       6,906                                      6,939  
                                         
Total additional required (4)
    -       192       -       9       7  

(1)  
Includes system peak load plus planning reserves.
(2)  
Includes 232 MW of peaking capacity at Reid Gardner Generating Station Unit No. 4, which is co-owned with CDWR, see Item 2, Properties.
(3)  
Includes 484 MW combined cycle unit at the Harry Allen Generating Station in 2011, and 5 MW at the Goodsprings renewable energy plant in 2011.
(4)  
Total additional required is the difference between the total requirements and total resources.  Total additional required represents the amount needed to achieve the forecasted system peak plus a planning reserve margin.

Energy Supply

The energy supply function at NPC encompasses the reliable and efficient operation of NPC’s owned generation, the procurement of all fuels and purchased power, and resource optimization.

NPC faces energy supply challenges for its load control area.  There is the potential for continued price volatility in NPC’s service territory, particularly during peak periods.  A greater dependence on generation from the wholesale markets subjects power prices to price volatilities due to available supply and gas prices.

In response to these energy supply challenges, NPC has adopted an approach to managing the energy supply function that has three primary elements.  The first element is a set of management guidelines that relate 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 a clear distinction between policy setting (or planning) and execution.  Lastly, NPC will continue to pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans.  Details of the Energy Supply function are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.

Total System

NPC manages a portfolio of energy supply options.  The availability of alternate resources allows NPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity.  During 2008, NPC generated approximately 67.5% of its total system requirements, purchasing the remaining 32.5% as shown below.

   
2008
   
2007
   
2006
 
   
MWh
   
% of Total
   
MWh
   
% of Total
   
MWh
   
% of Total
 
NPC Company Generation
                                   
     Gas/Oil
    10,976,006       49.5 %     10,437,115       45.3 %     8,093,020       36.1 %
     Coal
    3,992,392       18.0 %     4,083,262       17.7 %     4,067,209       18.2 %
          Total Generated
    14,968,398       67.5 %     14,520,377       63.0 %     12,160,229       54.3 %
                                                 
          Total Purchased
    7,190,431       32.5 %     8,510,429       37.0 %     10,248,394       45.7 %
                                                 
          Total System
    22,158,829       100.0 %     23,030,806       100.0 %     22,408,623       100.0 %

As a supplement to its own generation, NPC purchases spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements.  Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies.  NPC’s decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits.  Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods.  Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than NPC’s own generation, again, subject to net system import limits.  NPC’s 2008 company generated MWhs increased 3.1% from 2007.  NPC’s 2008 purchased power MWhs decreased 15.6% compared to 2007 due to NPC’s increased reliance on self generation and a decrease in total system demand.  See Energy Supply in Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding NPC’s purchasing strategies.

10

 
   Risk Management

See Item 7A, Quantitative and Qualitative Disclosures About Market Risk.

      Generation

NPC’s generation capacity consists of a combination of 33 gas, oil and coal generating units with a combined summer capacity of 4,002 MWs as described in Item 2, Properties.  In 2008, NPC generated approximately 67.5% of its total system requirements.

In 2008, NPC completed construction of the Clark Peaking Units for a total additional capacity of 619 MWs.  Currently, NPC is constructing a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen Generating Station with a commercial operation date prior to summer of 2011, which was approved by the PUCN in 2008 as an amendment to NPC’s IRP.  In addition, NPC received approval and completed the purchase of a 598 MW (nominally rated) natural gas fired, combined cycle power plant from Reliant Energy, Inc, now known as the Higgins Generating Station.  The addition of these units increases NPC’s ability to self generate.

Fuel Availability

NPC’s 2008 fuel requirements for electric generation were provided by natural gas, coal, and oil.  The average costs of gas, coal, and oil for energy generation per MMBTU for the years 2004 through 2008, along with the percentage contribution to NPC’s total fuel requirements were as follows:

 
Average Consumption Cost & Percentage Contribution to Total Fuel Requirement
 
                 
 
Gas
 
Coal
 
Oil
 
$/MMBTU
Percent
 
$/MMBTU
Percent
 
$/MMBTU
Percent
2008
7.79
66.5%
 
2.17
33.5%
 
18.87
 0.0%
2007
6.32
64.4%
 
1.89
35.6%
 
17.17
 0.0%
2006
7.40
58.8%
 
1.63
41.1%
 
16.66
0.1%
2005
6.18
32.7%
 
1.59
67.1%
 
13.50
0.1%
2004
6.13
27.3%
 
1.33
72.6%
 
  8.75
0.1%

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.

Natural gas supplies are procured one season ahead of use through a competitive bidding process.  The physical gas prices are set at an appropriate industry index during the month of current delivery.  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 continues to optimize the use of the Lenzie Generating Station and the Silverhawk Generating Station, as well as the recently acquired Higgins Generating Station, which results in a reduction of NPC’s exposure to fluctuations in the market price of gas.  These units are more efficient than most generating facilities supplying energy to the market in which NPC purchases energy and, consequently, will require less fuel to produce the same amount of electric energy.  This trend is expected to continue in 2009 and beyond.

NPC utilizes a laddered strategy with respect to coal supply and has long term coal contracts with Arch Coal Company (expires 2011), Andalex Resources, Inc. (expires 2010), Hiawatha Mining Co. (expires 2012) and Bowie Resources (expires 2012) to supply the Reid Gardner Generating Station.  These contracts represent 83% of projected coal requirements for 2009, 59% for 2010, 32% for 2011 and 9% for 2012.

As of December 31, 2008, Reid Gardner Generating Station’s coal inventory level was 272,744 tons, or approximately 81 days of consumption at 100% capacity.

A transportation services contract with Union Pacific Railroad provides for deliveries from the Provo, Utah interchange as well as various mines in Utah and Colorado, to the Reid Gardner Generating Station in Moapa, Nevada.  The Utah Railway contract provides for delivery of all coal not loaded by the Union Pacific in Helper, Utah to interchange with Union Pacific at Provo, Utah.  The Union Pacific contract expires December 31, 2009.

11

 
Coal for the Navajo Generating Station, which is jointly owned and operated by Salt River, is obtained from surface mining operations conducted by Peabody on portions of the Black Mesa in Arizona within the Navajo and Hopi Indian tribes (the Tribes) reservations.  The Navajo Generating Station's supply contract expires June 2011, with an option provided to NPC to extend for an additional 15 years.

   Purchased Power
 
NPC, under the guidelines set forth in the NPC ESP, continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs.  During 2008, NPC purchased 32.5% of its total energy requirements.
 
 
NPC purchases both forward firm energy and spot market energy based on economics, operating reserve margins and unit availability.  NPC seeks to manage its growing loads efficiently by utilizing its generation resources in conjunction with buying and selling opportunities in the market.
 
NPC has entered into long term purchase power contracts (3 or more years) generated by gas, hydro and renewable resource facilities with a total MW capacity of 2,090 and contract termination dates ranging from 2013 to 2032.  Included in these contracts are 404 MWs of capacity of renewable energy of which approximately 325 MWs of capacity are under construction and not currently available.

NPC is a member of the WSPP and the SRSG.  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 credit rating, this was not a significant factor in 2008.
 
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.

NPC’s electric transmission system is 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 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 to the NPC distribution system.  NPC’s transmission system is directly interconnected with the transmission systems of Western Area Power Administration, Los Angeles Department of Water and Power, Southern California Edison, and PacifiCorp.  NPC currently is not directly interconnected with SPPC; however, the Utilities have proposed the EN-ti line which will link NPC’s and SPPC’s transmission system in the southern and northern portions of the state, allowing for the transfer of energy, including renewable resources between the Utilities.  The map below shows NPC’s transmission system and the proposed EN-ti line:

12

 
Nevada Power Map
 
 
Under the NERC guidelines, NPC is a Balancing Authority, a Transmission Operator, and a Transmission Owner 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 imports).  The Transmission Operator is responsible for the reliability of its local transmission system, and operates or directs the operations of the transmission facilities.  The Transmission Owner owns and maintains transmission facilities.  NPC also schedules power deliveries over its transmission system and maintains reliability through its operations and maintenance practices and by verifying that customers are matching loads with resources.

NPC plans, builds and operates a transmission system that delivered 21,851,031 MWh of electricity to customers in its Balancing Authority Area in 2008.  The NPC system handled a peak load of 5,504 MW in 2008 through 1,908 line miles of transmission lines and other transmission facilities ranging from 60 kV to 500 kV.  NPC processes 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 in this growing system.  In the last 10 years, due primarily to high customer growth, NPC has constructed major transmission projects with Centennial being the most recently completed project (100 miles).
 
 
13


 
   Transmission Regulatory Environment

Transmission for NPC's bundled retail customers is subject to the jurisdiction of the PUCN for rate making purposes.  NPC’s wholesale and retail access transmission services are regulated by the FERC under cost based regulation subject to the OATT which NPC operates under.  In accordance with the OATT, NPC offers 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 NPC provides for NPC’s bundled retail customers).

These services are all offered on a nondiscriminatory basis in that all potential customers, including NPC, have an equal opportunity to access the transmission system.  NPC’s transmission business is managed and operated independently from the energy marketing business in accordance with FERC Standards of Conduct.
 
NPC is a member 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.  In 2007 and 2008 the WestConnect members worked collaboratively to develop consistent responses to FERC Order 890 requirements and developed regional business practices including OATT Attachment K, Transmission Planning Process.  The Subregional Transmission Planning Committee was established to provide coordinated transmission planning across the WestConnect footprint, including the Southwest Area Transmission Group that NPC participates in and the Sierra Nevada Planning Group that SPPC participates in.

Integrated Resource Plan

NPC files an IRP every three years.  The IRP is prepared in compliance with Nevada laws and regulations and covers a 20 year period.  The IRP develops a comprehensive, integrated plan that considers customer energy requirements and proposes the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals.  The ultimate goal of the IRP is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of NPC’s customers.

In June 2006, NPC filed its 2006 triennial IRP with the PUCN and has since filed several amendments to the IRP.  The following are the key elements of the filing as amended:

·  
Approval was requested and subsequently obtained for the construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen Generating Station with a scheduled commercial operation date of June 1, 2011.  The estimated cost of this project is approximately $682 million (excluding AFUDC).  Additionally, the PUCN approved NPC’s request to include the Harry Allen Generating Station CWIP in rate base.  Following the PUCN's approval of NPC's 8th amendment to the 2006 IRP in October, 2008, the Nevada Attorney General's BCP filed a petition for a rehearing with respect to the portion of the PUCN's order approving the new combined cycle unit at the Harry Allen Generating Station.  The PUCN denied the petition on November 26, 2008.  On December 30, 2008, the BCP filed a petition for judicial review in the First Judicial District of the State of Nevada seeking a reversal of the PUCN's order as it relates to the Harry Allen Generating Station combined cycle unit and a remand of the matter to the PUCN to gather further evidence.

·  
Approval was requested and subsequently obtained to purchase the 598 MW (nominally rated) combined cycle Generating Station from Reliant Energy, LLC., now known as the Higgins Generating Station, for approximately $510 million, including costs for inventory and other closing costs and adjustments.  The purchase was completed in October 2008 and is included in NPC’s 2008 GRC.

·  
Approval was obtained to construct 619 MW (nominally rated) quick start combustion turbine units at the Clark Generating Station at a cost of approximately $384 million.  Construction of this project was completed in 2008.

·  
The PUCN granted the Utilities’ initial request in its IRP filing to proceed with the development of Phase I of the EEC and accompanying transmission line.  The PUCN also approved the Utilities’ request of $300 million for development activities associated with the EEC with a limitation of $155 million placed on expenditures until the Utilities have obtained the final air permit.  The PUCN approved the request to initially allocate the costs between NPC and SPPC using an 80/20 cost allocation, respectively.  Furthermore, the PUCN granted the Utilities’ request for critical facility designation, thereby allowing it to qualify for incentives to be determined at a later date.  Since then, the Utilities filed amendments in regards to EEC and the PUCN, in its order, outlined certain minimum information regarding the EEC that shall be provided in NPC’s 2009 IRP filing, including but not limited to an update of the engineering, construction and then current cost estimates of the EEC, a refined project schedule, an initial analysis of the benefits of joint system analysis, an update of environmental costs and economic benefits attributed to the EEC and an update on the status of all the required permits.  Additionally the limitation on expenditures was reduced to $130 million.  However, on February 9, 2009, NVE and the Utilities announced their intention to postpone their plan to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade.  The Utilities have spent approximately $71.1 million as of December 31, 2008 towards the development of the EEC, including costs relating to the development of the EN-ti line.

·  
Approval of various DSM programs was requested and obtained.

·  
Approval was requested and subsequently obtained to acquire a 50% interest in the Carson Lake Project, providing a minimum of 30 MW of geothermal renewable energy (from a nominal net of 24 MW to 40 MW) under the terms of a Joint Operating Agreement with an affiliate of Ormat Technologies, Inc.

·  
Approval was requested and subsequently obtained to construct the 6 MW Goodsprings Waste Heat Recovery Project at the compressor station on the Kern River Gas Pipeline.
 
 
14

 
·  
Approval was requested and subsequently obtained for various long-term power purchase agreements, primarily related to renewable energy, and long term tolling contracts.

·  
Approval was requested and subsequently obtained to expend $60 million on new ultra-low emission burners on the four combustion turbines serving the combined cycle units at the Clark Generating Station.

·  
Approval of an updated load forecast was requested and obtained.

Construction Program

NPC’s construction program 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 southern Nevada, regulatory considerations and impact to customers, NPC’s ability to raise necessary capital, and changes in environmental regulations.  Under NPC’s franchise agreements, it is obligated to provide a safe and reliable source of energy to its customers.  Capital construction expenditures and estimates are reflective of NPC’s obligation to serve its growing customer base.

Gross construction expenditures for 2008, including AFUDC, net salvage and CIAC, were $1.3 billion, and for the period 2004 through 2008, were $3.7 billion.  Estimated construction expenditures for PUCN approved projects, projects under contract, compliance projects and other base capital requirements are as follows (dollars in thousands):

   
2009
     
2010-2013
   
Total 5 - Year
 
Electric Facilities
                   
Generation
  $ 554,774     $ 805,079     $ 1,359,853  
Distribution
    128,530       580,124       708,654  
Transmission
    67,272       275,977       343,249  
Other
    77,488       163,205       240,693  
Total
  $ 828,064     $ 1,824,385     $ 2,652,449  

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

   
2009
     
2010-2013
   
Total 5 - Year
 
                     
Construction Expenditures
  $ 828,064     $ 1,824,385     $ 2,652,449  
AFUDC
    (64,436 )     (250,754 )     (315,190 )
Net Salvage/ Cost of Removal
    (10,100 )     (41,420 )     (51,520 )
Net Customer Advances and CIAC
    (22,300 )     (91,452 )     (113,752 )
           Total Cash Requirements
  $ 731,228     $ 1,440,759     $ 2,171,987  

Major PUCN approved projects included in the 5 year estimated construction expenditures are as follows (dollars in thousands):

Projects
 
MW
   
Approved by PUCN
   
Total Cost 2009
   
Total Project Cost Cash Flows
   
Cumulative Expenditures as of December 31, 2008
   
Projected in service completion date year
 
 EEC (1)
    1,500     $ 104,000     $ 24,000     $ 104,000     $ 57,085      
-
 
 Harry Allen Generating Station
    500       681,869       321,510       682,043       140,618    
2011
 
 Renewable Projects (2)
    26       112,300       48,692       120,871       10,858      
2010-2011
 
 Reid Gardner Generating Station environmental compliance
          83,940       11,700       93,760       82,060    
2009
 
 Clark Generating Station environmental compliance
          60,000       23,116       58,861       35,745    
2009
 

(1) See discussion below regarding the EEC by the PUCN.  These costs assume 80% allocated to NPC.
(2) MWs reflect NPC’s expected ownership share of these projects.

As discussed under the IRP, the PUCN approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent approximately $71.1 million, which includes costs related to the EN-ti line, as of December 31, 2008.  However, on February 9, 2009, NVE and the Utilities announced their intention to postpone the construction of the EEC but plan to proceed with the construction of the EN-ti line.  In 2009, the Utilities intend to file amendments to their IRP’s requesting PUCN approval to accelerate the development of the EN-ti line.

In 2008 the PUCN approved the construction of a new 500 MW (nominally rated) natural gas combined cycle electric generating plant at NPC’s Harry Allen Generating Station.  This facility, 25 miles northeast of Las Vegas, is expected to commence operations by 2011.
 
 
15

 
NPC has various renewable energy projects, including wind, solar and geothermal, under development and negotiation.  In 2008, the PUCN approved the Carson Lake project and Goodsprings Waste Heat Recovery project for $91 million and $21.3 million respectively.  The Carson Lake project and the Goodsprings Waste Heat Recovery project are scheduled for commercial operation in 2011 and 2010, respectively.

NPC has entered into a joint development agreement, the China Mountain Wind Project, for approximately $238 million.  Under the joint development agreement, NPC has the opportunity to evaluate the feasibility of the project.  The PUCN has not yet approved the project; and as such, it has not been included in the above tables.

Reid Gardner Generating Station major capital and environmental projects include approximately $83.9 million of items previously approved by the PUCN and agreed upon with the EPA in April 2007.  In addition, NPC is expecting to incur costs with respect to major projects at the Reid Gardner Generating Station of approximately $87.2 million for certain infrastructure and environmental projects as agreed upon with the NDEP and other compliance projects for which NPC has not received PUCN approval, but are included in the gross construction expenditures and estimated cash requirements.  See Note 13, Commitments and Contingencies in the Notes to Financial Statements.
 
    The Clark Generating Station major capital and environmental projects include the installation of capital equipment as agreed upon in the consent decree between NPC and the EPA in August 2007.

SIERRA PACIFIC POWER COMPANY

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 two regulated business segments, SPPC electric and SPPC natural gas service, which are discussed separately in this section.  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.

SPPC Electric

Business and Competitive Environment

   Overview

SPPC is a public utility that generates, transmits and distributes electric energy to approximately 366,000 customers.  The service territory covers over 50,000 square miles of western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area.

   Electric Operations

SPPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors.  In addition to customer growth, demand and resulting electric revenues are impacted by rate changes, seasonal or atypical weather and customer use.  SPPC’s peak demand occurs in the summer with a slightly lower peak demand in the winter.  Therefore, SPPC’s electric revenues and associated expenses are not incurred or generated evenly throughout the year.

To serve its customer base, SPPC generates electricity and purchases power in accordance with an ESP, approved by the PUCN, as discussed in more detail later in this section and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.  In a continued effort to reduce reliance on purchased power, SPPC completed the construction of a 541 MW gas-fired combined-cycle plant at Tracy, east of Reno during 2008.

Nevada regulations require SPPC to file GRCs every three years with the PUCN to adjust rates including cost of service and return on investment.  Nevada state regulations also require SPPC to file annual DEAA applications to either recover or refund 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, SPPC is required quarterly to file to reset BTER reflecting more recent fuel and purchased power costs.  Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.

The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting, and other matters in connection with SPPC’s sale of electricity for resale and interstate transmission.  The FERC also has jurisdiction over the natural gas pipeline companies from which SPPC buys transportation for natural gas.

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   Competition

Nevada state law allows commercial customers with an average annual load of 1 MW or more to 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 certain public interest standards.  In particular, departing customers must secure new energy resources that are not under contract to SPPC, the departure must not burden SPPC 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 SPPC.  Customers wishing to choose a new supplier must provide 180-day notice to SPPC.  SPPC would continue to provide transmission, distribution, metering, and billing services to such customers.  Management believes that those customers securing energy from new energy suppliers will reduce SPPC’s need to purchase power from potentially volatile wholesale energy markets.

Newmont Mining Corporation achieved full commercial production of a new 204 MW (nominally rated) coal-fired power plant located in northeastern Nevada on May 1, 2008.  In 2007, SPPC and Newmont entered into a wholesale power sale agreement and a new form of retail service, General Service New Generation (GS-4NG).  Newmont will sell the electrical output from its plant to SPPC for at least 15 years under the long-term wholesale, purchased power agreement, and remain a retail customer of SPPC during at least that period under the terms of a retail service agreement and pursuant to the new GS-4NG rate schedule.

In 2008, after Barrick Gold Corporation completed its acquisition of the Cortez mining property in Nevada, it applied for and received approval from the PUCN for Cortez to depart SPPC’s retail system and, effective November 1, 2008, to be served under the terms of a DOS Agreement and the applicable DOS Tariff.  In 2005, Barrick Gold Corporation completed construction of a 118 MW generating facility and departed SPPC’s retain system, but continues to be served under a DOS agreement and applicable tariff.

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

Sales

In 2008, SPPC’s electric operations contributed approximately $1.0 billion, or 83%, of SPPC’s total revenues.  SPPC’s peak load reached 1,648 MW in August 2008.  Summer retail peak loads are primarily driven by air conditioning demand and irrigation pumping.  Winter retail electric peak loads are primarily driven by increased demand for space heating, air movement (with forced air gas and oil furnaces), and ski resorts (hotels, lifts, etc.).

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

   
MWh Sales (Billed and Unbilled)
 
                                     
   
2008
   
2007
   
2006
 
   
MWh
   
% of Total
   
MWh
   
% of Total
   
MWh
   
% of Total
 
Retail:
                                   
  Residential
    2,523,923       29.4 %     2,519,666       28.6 %     2,480,681       28.2 %
  Mining
    1,632,882       19.0 %     1,742,641       19.8 %     1,873,177       21.3 %
  Commercial and
  Industrial
    4,403,403       51.2 %     4,512,825       51.2 %     4,356,878       49.5 %
          Total Retail
    8,560,208       99.6 %     8,775,132       99.6 %     8,710,736       99.0 %
                                                 
Wholesale
    15,577       .2 %     14,581       0.2 %     69,757       0.8 %
Streetlights
    16,108       .2 %     15,943       0.2 %     15,502       0.2 %
                       TOTAL
    8,591,893       100.0 %     8,805,656       100.0 %     8,795,995       100.0 %

Total retail MWh sales decreased approximately 2.4% in 2008 from 2007, primarily due to a decrease in customer usage as a result of cooler summer weather and, to a lesser extent, changes in customer usage patterns.  Also contributing to the decrease in MWhs is the transition of certain customers to DOS as discussed below.

Mining is a leading industry in Northern Nevada and comprises one of SPPC’s largest classes of customers.  According to the Nevada Mining Association, spot gold price levels, coupled with Nevada’s reasonable regulatory environment, the state’s favorable geology for gold deposits, and the industry’s success in controlling its costs and attracting a high quality labor force offer a strong foundation for investment in continued mine development and the industry’s continuing high level of energy usage.  However, SPPC has seen a decline in mining MWhs as a result of certain customers transferring to DOS.

SPPC has long-term electric service agreements with nine of its largest major account commercial and industrial customers, with yearly revenues under these agreements totaling approximately $104 million.  For 2008, this represented approximately 10% of SPPC’s electric operating revenues of $1.0 billion.  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.

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Demand

Load and Resources Forecast

SPPC’s integrated peak electric demand decreased from 1,743 MW in 2007 to 1,648 MW in 2008.  Variations in energy usage occur as a result of varying weather conditions, economic conditions and other energy usage behaviors, such as conservation efforts.  This necessitates 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.

SPPC plans to meet its customers’ needs through a combination of company-owned generation and purchased power.  Remaining needs will be met through power purchased through RFPs or short term purchases.  See the Generations section and Purchased Power section below for details of SPPC’s generation and contracts for purchased power.

Below is a table summarizing the forecasted summer electric capacity requirement and resource needs of SPPC (assuming no curtailment of supply or load, and normal weather conditions):

   
Forecasted Electric Capacity
 
   
Requirements and Resources (MW)
 
                               
   
2009
   
2010
   
2011
   
2012
   
2013
 
                               
Total requirements (1)
    1,858       1,863       1,873       1,901       1,921  
                                         
Resources:
                                       
Company-owned existing generation
    1,577       1,577       1,577       1,567       1,567  
Contracts for power purchases
    320       449       449       449       297  
Total resources
    1,897       2,026       2,026       2,016       1,864  
                                         
Total additional required (2)
    -       -       -       -       57  

(1)  
Includes system peak load plus 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 forecasted system peak plus a planning reserve margin.

Energy Supply

The energy supply function at SPPC encompasses the reliable and efficient operation of SPPC’s owned generation, the procurement of all fuels and purchased power, and resource optimization.

SPPC faces energy supply challenges for its load control area.  There is the potential for continued price volatility in SPPC’s service territory, particularly during peak periods.  A greater dependence on generation from the wholesale markets subjects power prices to price volatilities due to available supply and gas prices.

In response to these energy supply challenges, SPPC has 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 a clear distinction between policy setting (or planning) and execution.  Lastly, SPPC will continue to pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans.  Details of the Energy Supply function are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.

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Total System

SPPC manages a portfolio of energy supply options.  The availability of alternate resources allows SPPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity.  During 2008, SPPC generated 50.5% of its total electric energy requirements, purchasing the remaining 49.5% as shown below.

   
2008
   
2007
   
2006
 
   
MWh
   
% of Total
   
MWh
   
% of Total
   
MWh
   
% of Total
 
SPPC Company Generation
                                   
    Gas/Oil
    2,819,767       30.7 %     2,282,636       24.3 %     2,167,898       23.2 %
    Coal
    1,812,918       19.8 %     1,705,789       18.1 %     1,848,591       19.8 %
    Hydro
    -       N/A       43,577       0.5 %     -       N/A  
          Total Generated
    4,632,685       50.5 %     4,032,002       42.9 %     4,016,489       43.0 %
                                                 
          Total Purchased
    4,547,062       49.5 %     5,376,364       57.1 %     5,334,341       57.0 %
                                                 
          Total System
    9,179,747       100.0 %     9,408,366       100.0 %     9,350,830       100.0 %

As a supplement to its own generation, SPPC purchases spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements.  Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies.  SPPC’s decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits.  Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods.  Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than SPPC’s own generation, again, subject to net system import limits.  SPPC’s 2008 company generation increased 14.9% compared to 2007.  SPPC’s 2008 purchased power total MWhs decreased 15.4% compared to 2007 due to SPPC’s increased reliance on self generation and a decrease in total demand.  See Energy Supply in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information.

   Risk Management

See Item 7A, Quantitative and Qualitative Disclosures About Market Risk.

   Generation

SPPC’s generation capacity consists of a combination of 35 gas, oil and coal generating units with a combined summer capacity of 1,577 MWs as described in Item 2, Properties.  In 2008, SPPC generated approximately 50.5% of its total system requirements.

In 2008, SPPC completed construction of a 541 MW (nominally rated) natural gas combined cycle facility at the existing Tracy Generating Station.  The units became operational in the summer of 2008.

   Fuel Availability

SPPC’s 2008 fuel requirements for electric generation were provided by natural gas, coal, and oil.  The average costs of gas, coal and oil for energy generation per MMBTU for the years 2004-2008, along with the percentage contribution to SPPC’s total fuel requirements, were as follows:


   
Average Consumption Cost & Percentage Contribution to Total Fuel
             
   
Gas
 
Coal
 
Oil
   
$/MMBTU
 
Percent
 
$/MMBTU
 
Percent
 
$/MMBTU
 
Percent
2008
 
8.95
 
57.5%
 
2.09
 
42.4%
 
20.90
 
0.2%
2007
 
8.34
 
57.8%
 
1.93
 
42.0%
 
12.10
 
0.2%
2006
 
8.92
 
55.9%
 
1.83
 
43.9%
 
10.15
 
0.3%
2005
 
7.87
 
56.8%
 
1.67
 
43.1%
 
7.37
 
0.1%
2004
 
7.32
 
53.1%
 
1.39
 
44.9%
 
6.14
 
2.0%

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.

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Natural gas supplies are procured one season ahead of use through a competitive bidding process.  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 by gas trading personnel 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 that provide for deliveries through December 31, 2009 and December 31, 2011 respectively.  These contracts represent 100% of the Valmy Generating Station’s projected coal requirements in 2009, and 78% for 2010, and 57% for 2011.

Union Pacific Railroad originates and delivers coal to the Valmy Generating Station.  An extension to the transportation services contract is in place that expires December 31, 2009.  Currently, SPPC is negotiating a new contract and does not expect any disruption to service.

As of December 31, 2008, Valmy Generating Station’s coal inventory level was 173,257 tons or approximately 60 days of consumption at 100% capacity.

SPPC meets its needs for residual oil and diesel for generation through purchases on the spot market.  SPPC attempts to maintain an actual residual oil inventory target level of about 325,000 barrels, which is equal to a 14-day supply at full load operation.  Diesel inventory levels are kept at about five days full load operation supply since the diesel supply can be procured at various petroleum product terminals in and around the Reno-Sparks area.

   Purchased Power

SPPC, under the guidelines set forth in the SPPC ESP, continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs.  During 2008, SPPC purchased 49.5% of its total energy requirement.

SPPC purchases hydroelectric and thermal generation spot market energy, by the hour and by monthly RFP’s, based upon economics and system import limits.  Firm energy is also purchased during peak load periods as required to supply load and maintain adequate operating reserve margins.  As off-system energy costs increase, SPPC supplies a higher percentage of its native load utilizing its fossil fuel generation.

SPPC has entered into long term purchase power contracts (3 or more years) generated by coal, gas and renewable resource facilities, with a total MW capacity of 470 and contract termination dates ranging from 2009 to 2039.  Included in these contracts are 192 MWs of capacity of renewable energy.

As a result of SPPC’s improved credit quality during 2008, SPPC was able to eliminate pre-payments to counterparties for fuel; and reduce the number of counterparties requiring modified payment terms from the previous year.

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 facilities 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 credit quality, this was not a significant factor in 2008.

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.

SPPC’s electric transmission system is 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 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.

SPPC’s transmission system links generating units within the SPPC Balancing Authority Area to the SPPC distribution system.  SPPC’s transmission system is directly interconnected with the transmission systems 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.  SPPC currently is not directly interconnected with NPC; however, the Utilities have proposed the EN-ti line which will link NPC’s and SPPC’s transmission system in the southern and northern portions of the state, allowing for the transfer of energy, including renewable resources between the Utilities.  The map below shows SPPC’s transmission system and proposed EN-ti line:

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Sierra Pacific Map

Under the NERC guidelines, SPPC is a Balancing Authority, a Transmission Operator, and a Transmission Owner 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 imports).  The Transmission Operator is responsible for the reliability of its local transmission system, and operates or directs the operations of the transmission facilities.  The Transmission Owner owns and maintains transmission facilities.  SPPC schedules power deliveries over its transmission system and maintains reliability through its operations and maintenance practices and by verifying that customers are matching loads with resources.

SPPC plans, builds and operates a transmission system that delivered 8,591,893 MWh of electricity to customers in its Balancing Authority Area in 2008.  The SPPC system handled a peak load of 1,648 MW in 2008 through 2,137 line miles of transmission lines and other facilities ranging from 60 kV to 345 kV.  SPPC processes 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 in this growing system.

In the last 10 years, due primarily to high customer growth, SPPC has constructed major high voltage transmission projects.  The projects completed include the Alturas Line (167 miles) and the Falcon – Gonder Line (180 miles) among others which increased SPPC’s import capabilities.

   Transmission Regulatory Environment

Transmission for SPPC’s bundled retail customers is subject to the jurisdiction of the PUCN for rate making purposes.  SPPC’s wholesale and retail access transmission services are regulated by the FERC under cost based regulation subject to the OATT SPPC operates under.  In accordance with the OATT, SPPC offers 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 SPPC provides for SPPC’s bundled retail customers).

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

SPPC is a member 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.  In 2007 and 2008 the WestConnect members worked collaboratively to develop consistent responses to FERC Order 890 requirements and developed regional business practices including OATT Attachment K, Transmission Planning Process.  The Subregional Transmission Planning Committee was established to provide coordinated transmission planning across the WestConnect footprint, including the Southwest Area Transmission Group that NPC participates in and the Sierra Nevada Planning Group that SPPC participates in.

SPPC Gas

Business and Competitive Environment

Overview

SPPC provides natural gas service to approximately 149,000 customers in an area of about 800 square miles in Nevada’s Reno/Sparks area.  SPPC also procures natural gas for electric power generation at the Tracy and Fort Churchill Generating Stations east of Reno.

   Gas Operations

SPPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors.  In addition to customer growth and demand, resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use.  Gas demand and revenues are very seasonal for SPPC Gas.  Average daily temperatures range from 72 to 34 degrees Fahrenheit and the average high temperature to low temperature range from 91 to 21 degrees Fahrenheit.  This wide temperature swing causes gas volumes to vary substantially depending on the weather.

In recent years, natural gas prices have trended upward and fluctuated widely, depending on such factors as weather, supply, demand, and the cost of competing fuels.  Natural gas supply and demand fundamentals indicate immediate continued volatility.  Relatively low-priced sources of fuel continue to be depleted and new supply is expensive to bring on-line.  Additionally, gas demand has steadily increased, particularly due to an increase in gas-fired electric generation on a national level.  Much of SPPC’s electric generation resources use natural gas as their only fuel source.

SPPC is well connected with several major gas producing regions and the gas transport system into Northern Nevada is robust.  SPPC’s gas distribution system receives gas supplies from two interstate natural gas pipelines:  the Paiute Pipeline Company and the TGTC.  In addition, SPPC has contracted for natural gas storage services to supplement firm and spot market purchases.

Nevada state regulations require annual filings to reset base purchased gas rates and recover deferred balances that include purchased gas costs above or below amounts collected in current rates.  The regulations also require a Gas Supply Report as well as a Gas Informational Report to be filed annually.  Natural gas commodity costs are passed directly through to customers on a dollar for dollar basis.  SPPC may also file GRCs to adjust gas division rates including cost of service and return on investment.  Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.

    Competition

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.  As of January 1, 2009, there were 14 large customers securing their own supplies.  These customers have a combined firm distribution load of approximately 5,639 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.

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Sales

SPPC’s natural gas business accounted for $210.0 million in 2008 operating revenues or 17.3% of SPPC’s total revenues from continuing operations.

Demand

Growth in all sectors is expected to continue, although at a much slower pace due to a general slow down in real estate development activity experienced in 2008 and expected to continue into 2009.  Projected peak demand, which will only occur when the calculated average of the high and low temperatures for a given day drops to negative 5 degrees Fahrenheit, is estimated to be 198,691 Dth per day for the winter of 2008/2009.

To secure gas supplies for power generation and the LDC, SPPC contracted for firm winter, summer, and annual gas supplies with over two dozen Canadian and domestic suppliers.  In 2008 seasonal and monthly gas supply net purchases averaged approximately 125,975 Dth per day with the winter period contracts averaging approximately 141,961 Dth per day, and the summer period contracts averaging approximately 114,620 Dth per day.

SPPC’s firm natural gas supply is supplemented with natural gas storage services and supplies from the Northwest Pipeline Co. 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.  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 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.

Following is a summary of SPPC’s transportation and storage portfolio as of December 31, 2008:

Firm Transportation Capacity
 
Dth per day firm
 
Term
         
Northwest
 
68,696
 
(Annual)
Paiute
 
68,696
 
(November through March)
Paiute
 
61,044
 
(April through October)
Paiute
 
23,000
 
(LNG tank to Reno/Sparks)
Nova
 
130,217
 
(Annual)
ANG
 
128,932
 
(Annual)
GTN
 
140,169
 
(November through April)
GTN
 
79,899
 
(May through October)
Tuscarora
 
172,823
 
(Annual)
         
Storage Capacity
       
         
Williams:
 
281,242
 
Inventory capability at Jackson Prairie
   
12,687
 
Withdrawal capability per day from Jackson Prairie
Paiute:
 
303,604
 
Inventory capability at Paiute LNG
   
23,000
 
LNG Storage

Total LDC Dth supply requirements in 2008 and 2007 were 15.1 million Dth and 15.4 million Dth, respectively.  Electric generating fuel requirements for 2008 and 2007 were 31.0 million Dth and 25.0 million Dth, respectively.

Gas Distribution

As of December 31, 2008, SPPC owned and operated 1,964 miles of three-inch equivalent natural gas distribution piping.  SPPC constructed a combined total of 3,237 feet of new 18 inch steel gas main in 2008 to support system growth.  In addition, and as part of its on going main and service replacement program, SPPC replaced approximately 18,213 feet of gas main of various sizes and approximately 256 service pipes that lead from the gas main to the individual meters in 2008.

SPPC Electric and Gas

Integrated Resource Plan

SPPC files an IRP every three years.  The IRP is prepared in compliance with Nevada laws and regulations and covers a 20 year period.  The IRP develops a comprehensive, integrated plan that considers customer energy requirements and proposes the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals.  The ultimate goal of the IRP is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of SPPC’s customers.

In June 2007, SPPC filed its 2007 triennial IRP with the PUCN and has since filed several amendments to the IRP.  The following are the key elements of the filing as amended:
 
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·    The PUCN granted the Utilities’ initial request in its IRP filing to proceed with the development of Phase I of the EEC and accompanying transmission line.  The PUCN also approved the Utilities’ request of $300 million for development activities associated with the EEC with a limitation of $155 million placed on expenditures until the Utilities have obtained the final air permit.  The PUCN approved the request to initially allocate the costs between NPC and SPPC using an 80/20 cost allocation, respectively.  Furthermore, the PUCN granted the Utilities’ requests for critical facility designation, thereby allowing it to qualify for incentives to be determined at a later date.  Since then, the Utilities filed amendments in regards to EEC and the PUCN, in its order, outlined certain minimum information regarding the EEC that shall be provided by SPPC’s amendment to its 2007 IRP to be filed in conjunction with NPC’s 2009 IRP filing, including but not limited to an update of the engineering, construction and then current cost estimates of the EEC, a refined project schedule, an initial analysis of the benefits of joint system analysis, a update of environmental costs and economic benefits attributed to the EEC and an update on the status of all the required permits.  Additionally, the limitation on expenditures was reduced to $130 million.  However, on February 9, 2009, NVE and the Utilities announced their intention to postpone their plan to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade.  The Utilities have spent approximately $71.1 million as of December 31, 2008 towards the development of the EEC, including costs associated with the EN-ti line.
   
·  
The PUCN approved expenditures of $16.5 million on the replacement of the diesel units in Kings Beach, California.

Construction Program

SPPC’s construction program and estimated expenditures are subject to continuing review and are periodically revised to include the rate of load growth, escalation of construction costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in northern Nevada, regulatory considerations and impact to customers.  SPPC’s ability to raise necessary capital, SPPC’s other cash needs and changes in environmental regulation.  Under SPPC’s franchise agreements, it is obligated to provide a safe and reliable source of energy to its customers.  Capital construction expenditures and estimates are reflective of SPPC’s obligation to serve its growing customer base.

Gross construction expenditures for 2008, including AFUDC  and CIAC, were $221 million, and for the period 2004 through 2008, were $1.2 billion.  Estimated construction expenditures for PUCN approved projects, projects under construction, compliance projects and base capital requirements, are as follows (dollars in thousands):

   
2009
     
2010-2013
   
Total 5 - Year
 
Electric Facilities:
                   
Generation
  $ 29,102     $ 110,031     $ 139,133  
Distribution
    63,142       259,266       322,408  
Transmission
    68,634       289,723       358,357  
Other
    31,271       53,934       85,205  
TOTAL
    192,149       712,954       905,103  
                         
Gas Facilities:
                       
Distribution
    13,469       63,097       76,566  
Other
    180       2,461       2,641  
TOTAL
    13,649       65,558       79,207  
                         
Common Facilities
    13,028       49,453       62,481  
                         
TOTAL
  $ 218,826     $ 827,965     $ 1,046,791  

Total estimated cash requirements related to construction projects consist of the following (dollars in thousands):
 
   
2009
     
2010-2013
   
Total 5 - Year
 
                     
Construction Expenditures
  $ 218,826     $ 827,965     $ 1,046,791  
AFUDC
    (8,520 )     (59,204 )     (67,724 )
Net Salvage/ Cost of Removal
    (1,647 )     (6,631 )     (8,278 )
Net Customer Advances and CIAC
    (19,376 )     (77,517 )     (96,893 )
                         
           Total Cash Requirements
  $ 189,283     $ 684,613     $ 873,896  

As discussed under the IRP, the PUCN approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent approximately $71.1 million, which includes costs related to the EN-ti line, as of December 31, 2008.  However, on February 9, 2009, NVE and the Utilities announced their intention to postpone the construction of the EEC but plan to proceed with the construction of the EN-ti line.  In 2009, the Utilities intend to file amendments to their IRP’s requesting PUCN approval to accelerate the development of the EN-ti line.
 
 
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OTHER SUBSIDIARIES OF NV ENERGY, INC.

Sierra Pacific Communications

SPC was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure.  SPC entered 2004 with two distinct business areas.  The first involved a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (the Long Haul System) and the second was the Metro Area Network (MAN) business in Las Vegas and Reno, Nevada.  In 2004 SPC disposed of their MAN assets.  Currently, management is assessing various business opportunities in regards to the remaining Long Haul System.  In 2008, SPC recorded an impairment of the Long Haul System of approximately $3.8 million, net of taxes.  As of December 31, 2008, SPC’s recorded asset value for the Long Haul System is approximately $4.1 million.  SPC does not otherwise contribute significantly to the results of operations of NVE.

Lands of Sierra

LOS was organized in 1964 to develop and manage SPPC’s non-utility property in Nevada and California.  These properties previously included retail, industrial, office and residential sites, timberland, and other properties.  In keeping with NVE's strategy to focus on its core energy business, LOS continues to sell its remaining properties, which are located in Nevada and are of minimal book value.  LOS does not materially contribute to the results of operations of NVE.

For a discussion of other subsidiaries’ results of operations, refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ENVIRONMENTAL (NVE, NPC AND SPPC)
 
As with other utilities, NPC and SPPC are subject to federal, state and local regulations governing air, water quality, hazardous and solid waste, land use and other environmental considerations.  Nevada’s Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities.  The EPA, NDEP and Clark County Department of Air Quality and Environmental Management administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste.  The most significant environmental laws and regulations affecting NPC and SPPC include:

Federal Environmental Laws and Regulations

·  
Clean Air Standards

The Clean Air Act 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 Clean Air Act 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 Clean Air Act to target specific emissions from electric utility generating plants.  If enacted, this legislation could require reductions in emissions of nitrogen oxides, sulfur dioxide, mercury and/or other pollutants.

The Clean Air Act programs, which most directly affect NVE’s electric generating facilities, are described below.

Regulated Air Pollutants

The federal Clean Air Mercury Rule (CAMR) was based on a national cap-and-trade system which was designed to achieve a 70 percent reduction in mercury emissions.  It affected all coal and oil-fired generating units across the country greater than 25 MWs.  Compliance with this rule was to have occurred in two phases, with the first phase beginning in 2010 and the second phase in 2018.  Under this Federal program, states would have been allocated mercury allowances based on coal type and their baseline heat input relative to other states.  Each electric generating unit would have been allocated mercury allowances based on its percentage of total coal heat input for the state.  In late 2006, the State of Nevada proposed its own mercury emission reduction rule in keeping with EPA’s proposed model program.

On February 8, 2008, in State of New Jersey v. EPA, the US Court of Appeals for the District of Columbia Circuit vacated two EPA rules issued under the Clean Air Act regarding the emission of hazardous air pollutants ("HAPs") from electric utility steam generating units ("EGUs"), including the CAMR as well as a rule delisting EGUs from HAPs requirements.  EPA and industry groups each filed separate petitions for certiorari with the U.S. Supreme Court on Oct. 17, 2008 asking the Court to hear their appeal.  On January 7, 2009, EPA issued a memo to regional administrators regarding the application of Clean Air Act Section 112(g) (case by case MACT) to Coal and Oil-fired Generating Units that began actual construction or reconstruction between March 29, 2005 and March 14, 2008.  Then, on January 29, 2009, the EPA requested that the Department of Justice withdraw the Petition for Writ of Certiorari in the State of New Jersey case, stating in part that EPA intends to develop emission standard for utility units under section 112 of the Clean Air Act and thus to abide by the D.C. Circuit’s decision in this case.  Based on this development, it appears that EPA will work to propose a new maximum achievable control technology ("MACT") standard for mercury emissions.  The State of Nevada is also making a determination of whether or not to proceed with a new State Mercury rule.  While the final outcome and timing for EPA's and/or the State’s actions cannot be estimated at this point, the Utilities will continue to monitor this issue and assess its potential impact on our generation fleet as new information becomes available.

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Regional Haze Rules 

In June 2005, the EPA finalized amendments to the July 1999 regional haze rules; thereby requiring states to develop implementation plans 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 with an expected rollout occurring in early 2009, and NVE has been actively involved in the stakeholder process.  The impacted BART units are Reid Gardner Generating Station Units 1, 2 & 3; Ft. Churchill Generating Station Units 1 & 2; and Tracy Generating Station Units 1, 2 & 3.  The draft Nevada BART regulation 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 unit retirement.  Due to the uncertainties of technology requirements necessary to meet the target emission rates, implementation timing and the economic profile of the impacted units at the projected time of implementation, NVE is not able to estimate the cost impact to its system at this time.

·  
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 cooling water intake 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 cooling water intake structures and thermal discharges of wastewater from power generation facilities do not specifically apply to the NPC and SPPC generation sites.
 
·  
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.
 
Federal Legislative and Regulatory Initiatives

·  
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.  The United States currently has no regulations addressing greenhouse gas emissions; the main emphasis to date being reliance on voluntary measures.  While several bills have been introduced in Congress that would address carbon dioxide emissions, none have been enacted to-date.  Environmental advocacy groups and regulatory agencies in the United States are also focusing considerable attention on carbon dioxide emissions from power generating facilities and their potential role in climate change. 
 
In July 2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR) that requested comments on a wide variety of issues the agency is considering in formulating its response to the U.S. Supreme Court’s decision in Massachusetts v. EPA.  In that case, the court determined that CO2 is an “air pollutant” and that the Federal EPA has authority to regulate mobile sources of CO2 emissions under the Clean Air Act if appropriate findings are made.  The Federal EPA has identified a number of issues that could affect stationary sources, such as electric generating plants, if the necessary findings are made for mobile sources, including the potential regulation of CO2 emissions for both new and existing stationary sources under the NSR programs of the CAA.  As well, additional legislative measures to address CO2 and other green house gases have been introduced in Congress, and such legislative actions as well as any new programs introduced by the new Administration could impact our business.  However, at this time we cannot predict the timing or economic impact.

NVE has and will continue to identify projects that minimize or offset greenhouse gas emissions and believes precautionary actions to limit greenhouse gas emissions are appropriate.  In 2006, NVE joined the California Climate Action Registry (CCAR) and voluntarily committed to commence an annual inventory, certify and publicly report on greenhouse gas emissions from NPC and SPPC through this organization.  In 2008, NVE became a founding member of The Climate Registry which is a national organization.  At the close of 2008, NVE submitted its second year of verified emissions to the CCAR. 

·  
Water Supply

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.  Water resources for most of these facilities rely on regional aquifers that are not closely connected to transient drought conditions.  In the event that significant drought conditions were to occur, the Utilities would work with its water suppliers, regulators, and other stakeholders to implement agreements to minimize the effect on its operations.
 
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Every generation alternative – whether fossil fuels, nuclear, or renewable power options– has environmental and financial impacts.  NVE recognizes these impacts and closely links its business objective of generating reliable, cost-effective energy with its environmental responsibilities. 
 
NVE’s environmental philosophy accentuates prudent use of natural resources and to that end, NVE supports multiple program areas aimed at achieving overall air emission reductions.  Some examples are:

·  
Installation of commercially-proven pollution controls coupled with an emphasis on continued operational excellence to achieve further plant efficiency improvements.  NVE’s new natural gas-fired generating plants require the combustion of far less fuel than older facilities to produce each kWh of electrical output.  As new generation is added to the system, NVE is concurrently evaluating and eliminating older, less efficient units from its fleet.
·  
Maintenance of robust DSM programs, including energy efficiency and conservation education and support.  These programs increase the adoption of energy-efficient equipment by our customers, thereby creating savings on energy bills and potentially delaying the need for additional power plant, transmission, and distribution construction.
·  
Development of technology solutions through funding and participation in collaborative research programs for advanced coal technologies, as well as potential options for carbon sequestration.  NVE is currently participating with the Electric Power Research Institute (EPRI) to evaluate technologies potentially suitable for carbon capture.
·  
Expansion of company owned renewable energy sources and continued use of purchase power agreements and investments that focus on lower or non-emitting generation resources.  The State of Nevada mandates that an increasing percentage of the energy NVE sells must come from renewable sources, reaching 20 percent by 2015.  Refer to Purchase and Development of Renewable Resources earlier in this section.

GENERAL – EMPLOYEES (ALL)

NVE and its subsidiaries had 3,330 employees as of January 26, 2009, of which 1,901 were employed by NPC and 1,309 were employed by SPPC.

NPC’s amendment to its existing contract with the IBEW Local No. 396, which covers approximately 56% of NPC’s workforce, was ratified by the IBEW Local No. 396 on September 29, 2008.  The contract will be in effect through February 1, 2011.

SPPC’s current contract with the IBEW Local No. 1245, which covers approximately 62% of SPPC’s workforce, was renegotiated and ratified in February 28, 2007 and is in effect until December 31, 2009.

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 and California.  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 2008 the Utilities collected $129.5 million in franchise or other fees based on gross revenues.  They collected $10.0 million in UEC based on consumption.  They also paid and recorded as expense $2.9 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
 
The Utilities plan to make significant capital expenditures to construct new generation and transmission facilities. In addition, the Utilities require liquidity to bridge the cost of fuel and purchased power and other operating activities until recovered through rates.  If we are unable to finance such construction or limit the amount of capital expenditures associated with those facilities to forecasted levels, finance or generate sufficient liquidity for fuel and purchased power including, risk management activities, and/or recover amounts spent on construction, fuel and purchased power and other operating activities through future filings with the PUCN, and/or maintain our credit ratings, our financial condition and results of operation could be adversely affected.

Our long term business objectives include plans to construct new generation and transmission facilities.  We do not currently generate sufficient cash flow to fund the construction plan.  Significant construction capital requirements and liquidity to bridge the cost of fuel and purchased power and other operating activities, until recovered through rates, require that the Utilities may finance through significant additional borrowings under the Utilities’ respective credit facilities, through additional debt financings in private or public offerings or through debt or equity financings by NVE.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, NVE.  We cannot be sure that we will be able to obtain financing on favorable terms, or at all, depending on financial market conditions, including the effect of recent volatility in financial and credit markets, changes in availability and cost of capital either due to market conditions or as a result of the Utilities’ credit ratings, or interest rate fluctuations.  Neither can we be sure that we will be successful in limiting capital expenditures to planned amounts, particularly in the event of escalating costs for materials, labor and environmental compliance, timing delays and other economic factors.  If we cannot obtain favorable financing arrangements for our planned capital expenditures, limit such capital expenditures to forecasted amounts, finance or generate sufficient liquidity for fuel and purchased, including risk management activities and other operating costs, and/or recover or timely recover amounts spent on construction, fuel and purchased power and other operating activities through future filings with the PUCN, and/or maintain our credit ratings, our financial condition and results of operations could be adversely affected.

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If the Utilities do not receive favorable rulings in their future GRCs, it will 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’ pending or future GRCs.  Inadequate base energy rates would have a significant adverse effect on the Utilities’ financial condition and future results of operations and could cause downgrades of their securities by the rating agencies and make it significantly more difficult or expensive to finance operations and construction projects and to buy fuel, natural gas and purchased power from third parties.
 
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 the Las Vegas portion of our service area.  The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets, including availability and cost of credit, inflation rates, monetary policy and unemployment rates.  A lower level of economic activity, changes in discretionary spending and decreased tourism activity in Las Vegas might result in a decline in energy consumption, which may adversely affect our revenues and future growth.  Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources".

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay on a timely basis, increase customer bankruptcies, and lead to increased bad debt.  It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur. 

Adverse investment returns on pension plan assets and other factors may increase NVE’s pension liability and pension funding requirements.

            Substantially all of NVE employees are covered by a defined benefit pension plan.  At present, the pension plan is underfunded in that the projected pension benefit obligation exceeds the aggregate fair value of plan assets.  The funded status of the plan can be affected by 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 plan assets will be sufficient to cover future liabilities.  Although NVE has made significant contributions to its pension plan in recent years, it is possible that NVE could incur a significant pension 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.

If Federal and/or State requirements are imposed on the Utilities mandating further emission reductions, including limitations on carbon dioxide (CO2) emissions, 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 United States have also been focusing considerable attention on carbon dioxide (CO2) emissions from power generation facilities and their potential role in climate change.  Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level that are aimed at the reduction of greenhouse gas emissions.  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, 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 required to be a responsible party for environmental clean up at sites identified 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 liability 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 and other toxic 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.
 
 
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    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.
 
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.
 
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.  As evidenced by the western utility crisis that began in 2000, 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.  Among the factors that could affect market prices for electricity and fuel are:
 
·  
prevailing market prices for coal, oil, natural gas and other fuels used in generation plants, including associated transportation costs, and supplies of such commodities;
 
·  
further concentration of gas as a source if the Utilities cannot diversify into coal; 
 
·  
changes in the regulatory framework for the commodities markets that they rely on for purchased power and fuel;
 
·  
liquidity in the general wholesale electricity market;
 
·  
the actions of external parties, such as the FERC or independent system operators, that may impose price limitations and other mechanisms to address volatility in the western energy markets;
 
·  
weather conditions impacting demand for electricity or availability of hydroelectric power or fuel supplies;
 
·  
union and labor relations;
 
·  
natural disasters, wars, acts of terrorism, embargoes and other catastrophic events; and
 
·  
changes in federal and state energy and environmental laws and regulations.
 
As a part of the Utilities’ risk management strategy, they focus on executing contracts for power deliveries to the Utilities’ physical points of delivery to mitigate the commodity-related risks listed above.  To the extent that open positions exist, fluctuating commodity prices could have a material adverse effect on their cash flows and their ability to operate and, consequently, on our financial condition.
 
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.  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 $327.0 million.  Refer to Management’s Discussion and Analysis, Factors Affecting Liquidity for NPC and SPPC.
 
As of February 20, 2009, NPC had approximately $289.7 million available under its $690 million revolving credit facilities and SPPC has approximately $110.6 million available under its $350 million revolving credit facility.  The combined effects of higher natural gas prices, significant deferred energy balances and ongoing under-recovery of fuel, energy and natural gas costs may have a negative effect on our short-term liquidity.
 

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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, 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.  Past disallowances in the Utilities’ deferred energy cases have been significant, which resulted in ratings downgrades of our debt securities and adversely affected our liquidity and access to capital markets.
 
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, gas 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.
 
Historically, the Utilities have purchased a significant 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 they do not have sufficient funds or access to liquidity to obtain their power requirements, particularly for NPC at the onset of the summer months, and are unable to obtain power through other means, their business, operations and financial condition will be materially adversely affected.
 
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 state utility commissions, 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.

On July 28, 2007, NVE’s BOD declared a quarterly cash dividend of $0.08 per share of Common Stock, payable on September 12, 2007.  This dividend was the first declared by the BOD since February 2002.  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.  Since the dividend on July 28, 2007 was declared, NVE’s BOD has declared in each of the successive quarters cash dividends; 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.
 
 
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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, 2008, the Utilities had approximately $4.8 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, 2008 financial statements, assuming an interest rate of 7%, NVE’s indebtedness restrictions would allow NVE and the Utilities to issue up to approximately $862 million of additional indebtedness in the aggregate, unless the indebtedness being issued 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.
 
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 energy sales from renewable energy sources, including biomass, geothermal, solar, waterpower and wind projects.  The Portfolio Standard requires the energy acquired from a renewable energy system be transmitted or distributed via a power line which is connected to a facility or system, owned, operated or controlled by the Utilities.  Other restrictions are placed on energy acquired from energy efficiency measures which may not exceed more than 25 percent of the Portfolio Standard and half of those savings must come from residential customers.

In years 2008 and 2009, the Portfolio Standard requires that nine percent and 12%, respectively of total retail energy sales come from renewable energy as measured by PEC's.  The Portfolio Standard increases by 3% every other year until it reaches 20% in 2015.  Moreover, not less than 5% of the total Portfolio Standard must be met by solar resources.

Due to periodic increases in the Portfolio Standard and increasing retail sales, the Utilities must acquire increasing amounts of renewable energy.  The Utilities’ success in meeting the increasing Portfolio Standard remains largely dependent on their ability to acquire additional renewable energy from either self-owned renewable generation facilities or the purchase of renewable energy from third-party developers and a decrease in demand through qualified conservation and energy efficiency measures.  In 2008, with the PUCN approval of transfers of SPPC’s excess non-solar Portfolio Credit’s, both NPC and SPPC were able to comply with the non-solar Portfolio Standard.  However, due to the late commercial operation of solar facilities, the Utilities did not meet the solar portion of the Portfolio Standard.  As a result of the Utilities’ efforts to add solar resources, the PUCN did not fine the Utilities for non-compliance with the solar requirement.  Although, historically, the Utilities have not been fined for non-compliance, the PUCN may levy fines on one or both of the Utilities; however, management cannot predict the amount if any that could be imposed.

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 working capital and 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.  On February 4, 2009, the PUCN approved financing authority for NPC to issue up to $1.25 billion of long term debt securities over a two-year period ending December 31, 2010; ongoing authority to maintain a revolving credit facility of up to $1.3 billion and authority to refinance up to approximately $471 million of long term debt securities.  SPPC has authority to issue up to $495 million of long term debt, which expires on December 31, 2009.  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.
 
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, recession, war and the threat of terrorism or epidemics 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 harm our business.  We cannot predict the extent to which the current recession, future terrorist and war activities, or epidemics, in the United States and elsewhere may affect us, directly or indirectly.  An extended period of reduced discretionary spending and/or disruptions or declines in airline 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.  In addition, instability in the financial markets as a result of the current recession, war, terrorism or epidemics may affect our ability to raise capital.
 
 
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ITEM 1B.                      UNRESOLVED STAFF COMMENTS
 
 
None.
 
 
ITEM 2.                      PROPERTIES
 
Substantially all of NPC’s and SPPC’s property in Nevada and California 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, as trustee, as amended and supplemented.

The following is a list of NPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2009 net capacity MW, and the years that the units were installed.

           
Number of
 
Summer MW
 
Commercial Operation
Plant Name
 
Type
 
Fuel
 
Units
 
Capacity
 
Year
Clark Generating Station (1)
 
Combined Cycle
 
Gas/Oil
 
6
 
430
 
1979, 1979, 1980, 1982, 1993, 1994
   
Gas
 
Gas/Oil
 
1
 
54
 
1973
   
Peakers
 
Gas
 
3
 
619
 
2008
Sunrise
 
Steam
 
Gas
 
1
 
80
 
1964
   
Gas
 
Gas/Oil
 
1
 
70
 
1974
Harry Allen Generating Station
 
Gas
 
Gas/Oil
 
2
 
142
 
1995, 2006
Lenzie Generating Station (2)
 
Combined Cycle
 
Gas
 
6
 
1,102
 
2006
Silverhawk Generating Station(3)
 
Combined Cycle
 
Gas
 
3
 
395
 
2004
Higgins Generating Station
 
Combined Cycle
 
Gas
 
3
 
530
 
2004
Mohave Generating Station (4)(5)
 
Steam
 
Coal
 
-
 
-
 
1971, 1971
Navajo Generating Station (6)
 
Steam
 
Coal
 
3
 
255
 
1974, 1975, 1976
Reid Gardner Generating Station (7)
 
Steam
 
Coal
 
4
 
325
 
1965, 1968, 1976, 1983
Total
         
33
 
4,002
   
                     

 
(1)   The two combined cycles at the Clark Generating Station each consist of two gas turbines, two Heat Recovery Steam Generators (HRSG), and one steam turbine.  In 1993 and 1994, the original four gas turbines (1979-1982) were combined with four new HRSGs and two new steam turbines to form the combined cycles.  Capacity of the Clark Peakers is derated due to low gas delivery pressure in the winter period.
 
(2)    The two combined cycles at the Lenzie Generating Station each consist of two gas turbines, two HRSGs and one steam turbine.
 
(3)   The acquisition of a 75% ownership interest in the Silverhawk Generating Station from Pinnacle West was consummated in 2006.  SNWA continues to hold a 25% ownership interest in the plant.  The combined cycle plant consists of two gas turbines, two HRSGs and one steam turbine.
 
(4)    Per a 1999 Consent Decree, the Mohave Generating Station ceased operation on December 31, 2005.  The PUCN approved establishing regulatory accounts related to the shutdown and decommissioning.  See Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements for further discussion.
 
(5)   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.
 
(6)   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).  There are four other partners: U.S. Bureau of Reclamation (24.3% interest), Los Angeles Dept. of Water & Power (21.2% interest), Arizona Public Service Co (14% interest), and Tucson Electric Power (7.5% interest).
 
(7)    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 25 MW of base load capacity and 232 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 summer capacity is 557 MW.

The following is a list of SPPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2009 net capacity MW, and the years that the units became operational.
 
 
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Number of
 
Summer MW
 
Commercial Operation
Plant Name
 
Type
 
Fuel
 
Units
 
Capacity
 
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 (1)
 
Combined Cycle
 
Gas
 
2
 
104
 
1996, 1996
Tracy Generating Station (2)
 
Combined Cycle
 
Gas
 
3
 
541
 
2008
Clark Mtn. CT's
 
Gas
 
Gas/Oil
 
2
 
132
 
1994, 1994
Valmy Generating Station(3)
 
Steam
 
Coal
 
2
 
261
 
1981, 1985