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, 2006
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Commission File
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Registrant, Address of Principal Executive Offices and Telephone
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I.R.S. Employer
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State of
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Number
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Number
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Identification Number
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Incorporation
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1-08788
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SIERRA PACIFIC RESOURCES
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88-0198358
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Nevada
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P.O. Box 30150 (6100 Neil Road)
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Reno, Nevada 89520-3150 (89511)
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(775) 834-4011
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2-28348
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NEVADA POWER COMPANY
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88-0420104
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Nevada
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6226 West Sahara Avenue
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Las Vegas, Nevada 89146
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(702) 367-5000
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0-00508
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SIERRA PACIFIC POWER COMPANY
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88-0044418
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Nevada
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P.O. Box 10100 (6100 Neil Road)
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Reno, Nevada 89520-0024 (89511)
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(775) 834-4011
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(Title of each class)
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(Name of exchange on which registered)
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Securities registered pursuant to Section 12(b) of the Act:
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Securities of Sierra Pacific Resources:
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Common Stock, $1.00 par value
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New York Stock Exchange
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7.803% Senior Notes Due 2012
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
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Securities of Nevada Power Company:
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Common Stock, $1.00 stated value
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Securities of Sierra Pacific Power Company:
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Common Stock, $3.75 par value
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act:
Sierra Pacific Resources Yes
þ
No
o
Nevada Power Company Yes
o
No
þ
Sierra Pacific Power Company Yes
o
No
þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes
o
No
þ
Indicate by check mark whether each of the registrants (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days. Yes
þ
No
o
Indicate by check mark 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, or a non-accelerated filer. (See definition of “accelerated filer and large accelerated
filer” in Rule 12b-2 of the Exchange Act).
Sierra Pacific Resources: Large accelerated filer
þ
Accelerated filer
o
Non-accelerated filer
o
Nevada Power Company: Large accelerated filer
o
Accelerated filer
o
Non-accelerated filer
þ
Sierra Pacific Power Company: Large accelerated filer
o
Accelerated filer
o
Non-accelerated filer
þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act). Yes
o
No
þ
(Response applicable to all registrants)
State the aggregate market value of Sierra Pacific Resources’ common stock held by
non-affiliates. As of June 30, 2006: $ 2,811,596,466
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 Sierra Pacific Resources outstanding at February 27, 2007:
221,252,060 Shares
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock,
$1.00 stated value, of Nevada Power Company.
Sierra Pacific Resources 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 Sierra Pacific Resources’ definitive proxy statement to be filed in connection
with the annual meeting of shareholders, to be held May 7, 2007, are incorporated by reference into
Part III hereof.
This combined Annual Report on Form 10-K is separately filed by Sierra Pacific Resources,
Nevada Power Company and Sierra Pacific Power Company. Information contained in this document
relating to Nevada Power Company is filed by Sierra Pacific Resources and separately by Nevada
Power Company on its own behalf. Nevada Power Company makes no representation as to information
relating to Sierra Pacific Resources 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
Sierra Pacific Resources and separately by Sierra Pacific Power Company on its own behalf. Sierra
Pacific Power Company makes no representation as to information relating to Sierra Pacific
Resources or its subsidiaries, except as it may relate to Sierra Pacific Power Company.
SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K
CONTENTS
2
FORWARD LOOKING STATEMENTS
The discussion of forward looking statements in Item 7, Management’s Discussion and Analysis
of Financial Condition and Results of Operations, is incorporated herein by reference.
PART I
ITEM 1. BUSINESS
SIERRA PACIFIC RESOURCES
Sierra Pacific Resources (SPR) 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 “SRP”. SPR’s mailing address is P.O. Box 30150 (6100 Neil Road), Reno,
Nevada 89520-3150 (89511).
SPR has six primary, wholly-owned subsidiaries: Nevada Power Company (NPC), Sierra Pacific
Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC),
Sierra Pacific Energy Company (SPE), and Lands of Sierra (LOS). References to SPR refer to the
consolidated entity, except where the context provides otherwise. NPC and SPPC are referred to
collectively in this report as the “Utilities.”
The Utilities operate three business segments, as defined by FASB Statement No. 131,
Disclosure about Segments of an Enterprise and Related Information
: NPC electric; SPPC electric;
and SPPC natural gas. Electric service is provided to Las Vegas and surrounding Clark County,
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 SPR’s financial position
and results of operations. Other subsidiaries either do not meet 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:
3
SPR continues to focus on a “back to the basics” strategy that emphasizes the Utilities’ core
business. 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.
The Utilities do not own generating facilities sufficient to meet the peak demands and
reliability needs of Nevada’s growing population and, as a result, NPC is forecasting to purchase
approximately 34% of its energy requirements from the wholesale market and SPPC is forecasting to
purchase approximately 49% of its energy requirements from the wholesale market for year 2007. For
the 2007 summer peak, NPC and SPPC have secured 100% of their forecast 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. In 2006, NPC and SPPC purchased approximately 45.7% and 56.9%, respectively, of total
system 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.
It is SPR’s strategy to grow the Utilities’ internal generating capacity in an effort to
reduce reliance on purchased power. Consistent with this strategy, in 2006 NPC completed
construction of the 1200 MW (unit ratings are nominal ratings) gas-fired Chuck Lenzie generating
station (“Lenzie”) and acquired a 75% interest in the 560 MW, gas-fired Silverhawk generating
station (“Silverhawk”). SPPC is constructing a new 514 MW facility at the Tracy Generating
Station. (For further details, see the following Generation sections for NPC and SPPC).
Additionally, as part of the strategy to grow and invest in, and improve the performance of
their regulated businesses, the Utilities announced their intention to develop a major energy
project located near Ely, Nevada, which will consist of two 750-megawatt coal fired generation
units and includes the construction of a 250-mile transmission line to interconnect the
transmission systems of NPC and SPPC. The total project costs are estimated to be $3.8 billion.
In November 2006, the Public Utilities Commission of Nevada (PUCN) approved NPC’s 2006 Integrated
Resource Plan (IRP) and SPPC’s thirteenth amendment to its 2004 IRP. Included in the PUCN’s
approval is Phase 1 of the construction of the Ely Energy Center. The PUCN approved spending up to
$300 million for development activities associated with Ely Energy Center with a limitation of $155
million placed on expenditures until the Utilities’ have obtained appropriate air permits. The
PUCN approved the Utilities’ request to initially allocate Phase 1 costs between NPC and SPPC on an
80/20 split, respectively. The PUCN also required NPC and SPPC to file amendments to their IRPs in
early 2008 once elements of the plan, including final costs, can be more accurately estimated.
This project and details discussed above are collectively referred to in this report as the “Ely
Energy Center”.
As a result of expanded service territory growth, both Utilities have added transmission
infrastructure. Discussions of new transmission lines are 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 1 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. One large SPPC mining
customer began operating a 118 MW generating facility in December of 2005 and another large SPPC
mining customer has begun construction of a 203 MW facility. These matters are discussed further
under Competition for NPC and SPPC below.
The Federal Energy Regulatory Commission (FERC), PUCN and, in the case of SPPC, the California
Public Utilities Commission (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 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 SPR’s, NPC’s and SPPC’s websites (www.sierrapacificresources.com,
www.nevadapower.com, and www.sierrapacific.com) through links on these websites 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 addresses are not part of this Form 10-K. Available
on the sierrapacificresources.com website is 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 SPR’s Board of Directors and our corporate
4
governance and standards of conduct guidelines. Printed copies of these documents may be
obtained free of charge by writing to SPR’s Corporate Secretary at Sierra Pacific Resources, P.O.
Box 30150, Reno, NV 89520-3150.
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 SPR in July 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada
89146.
Nevada Electric Investment Company (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% 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 2006, NPC served approximately 807,000 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.
Electric Operations
NPC is charged with meeting the growing 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 growing customer base, NPC purchases power and generates electricity in
accordance with an Energy Supply Plan, 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.
NPC’s strategy is to grow its internal generating capacity in an effort to reduce reliance on
purchased power. Consistent with this strategy, in 2006, NPC completed construction of Lenzie and
acquired Silverhawk, as discussed in further detail under the Generation section. Additionally, in
November 2006, the PUCN approved NPC’s 2006 IRP. Included in the PUCN’s approval of NPC’s 2006
IRP, are the Ely Energy Center and the construction of 600 MW peaking units at Clark Station at an
estimated cost of $395 million.
Nevada regulations require NPC to file general rate cases every two years with the PUCN to
adjust rates including cost of service and return on investment. Nevada state regulations also
require NPC to make annual filings to reset Base Tariff Energy Rates (BTER) and either recover or
credit balances that have been deferred representing fuel and purchased power costs incurred
compared with amounts collected in current retail rates. If necessary, NPC can file more than once
a year to seek a change in BTER to more closely match its actual 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.
Under federal law, wholesale rates charged by NPC are subject to certain jurisdictional
regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with
respect to 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 takes service.
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 will reduce NPC’s need to purchase power from potentially volatile wholesale
energy markets.
Currently, there are no material applications pending with the PUCN to exit the system in
NPC’s service territory.
5
Sales
NPC’s service territory continues to be among one of the fastest growing areas in the nation.
In 2006, NPC set 44,103 meters and it is forecasted that NPC will set over 37,000 in 2007. In
2006, NPC’s operating revenues were approximately $2.1 billion.
Summer peak loads are driven by air conditioning demand. Winter peak loads are low relative to
the summer peak. Winter load above the base amount is driven by air handling in forced air
furnaces. NPC’s peak load increased at an average annual growth rate of 4.7% over the past five
years, reaching 5,623 MW in July 2006. NPC’s retail total electric megawatt-hour (MWh) sales have
increased at an average annual growth rate of 4.3% over the past five years.
NPC’s electric customers by class contributed the following toward 2006, 2005 and 2004 MWh
sales:
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MWH Sales (Billed and Unbilled)
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2006
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2005
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2004
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Residential
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9,033,142
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42.3
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%
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8,288,309
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41.3
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%
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7,981,116
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40.1
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%
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Commercial & Industrial:
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Gaming/Recreation/Restaurants
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3,736,608
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17.5
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%
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3,711,790
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18.5
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%
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3,587,428
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18.0
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%
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All Other Retail
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8,049,753
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37.7
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%
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7,454,595
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37.1
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%
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7,038,692
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35.4
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%
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Total Retail
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20,819,503
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97.5
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%
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19,454,694
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96.9
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%
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18,607,236
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93.5
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%
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Wholesale
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244,128
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1.2
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%
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278,527
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1.4
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%
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870,398
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4.4
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%
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Sales to Public Authorities
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281,369
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1.3
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%
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349,912
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1.7
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%
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408,927
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2.1
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%
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Total
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21,345,000
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100
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%
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20,083,133
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100
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%
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19,886,561
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100
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%
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Growth in NPC’s residential class sales continues primarily as a result of new home
construction in Las Vegas and the surrounding areas. New home sales in the Las Vegas area in 2006
totaled 36,051.
Tourism and gaming remain southern Nevada’s leading industries and together comprise one of
NPC’s largest classes of customers (see Gaming/Recreation/Restaurants above). Currently, there are
two major projects under construction in Las Vegas with over $11 billion estimated in construction
costs.
The decrease in wholesale was due primarily to certain types of transactions that were
reported in sales for 2004 and are now being netted in purchase power.
The decrease in sales to public authorities was due to Southern Nevada Water Authority (SNWA)
moving to a distribution only service (DOS) tariff. The DOS tariff allows certain customers to
obtain energy from other entities but still continue to have that energy delivered over our
transmission and distribution lines
.
Demand
Load and Resources Forecast
NPC’s integrated peak electric demand rose from 5,563 MW in 2005 to 5,623 MW in 2006.
Variations in energy usage by NPC’s customers occur as a result of varying weather conditions and
other energy usage behaviors. 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. NPC filed its 2006 Integrated Resource Plan (IRP) with the PUCN, pursuant to
which the company received approval to commence construction of peaking units at Clark Station.
The first 413 MW of the Clark peaking units have a scheduled in-service date of June 2008 and the
remaining 206 MW has a scheduled in-service date of June 2009. These additional units will reduce
NPC’s reliance on purchased power. Remaining needs will be met through power purchases through
RFPs or short term purchases.
6
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):
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Forecasted Electric Capacity
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Requirements and Resources (MW)
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2007
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2008
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2009
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2010
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2011
(4)
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Total Requirements (1)
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6,745
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7,026
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|
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7,360
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7,668
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7,971
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Resources:
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Company-owned existing generation
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2,854
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2,854
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2,854
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2,854
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2,854
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Company-owned new generation (2)
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413
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619
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619
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619
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Contracts for power purchases
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3,891
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1,346
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|
1,374
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|
|
|
1,381
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|
|
|
1,507
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Total Resources
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6,745
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4,613
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4,847
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4,854
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|
|
|
4,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Additional Required (3)
|
|
|
—
|
|
|
|
2,413
|
|
|
|
2,513
|
|
|
|
2,814
|
|
|
|
2,991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Includes system peak load plus planning reserves.
|
|
|
|
(2)
|
|
Clark Station peaking units operational in 2008 and 2009.
|
|
|
|
(3)
|
|
Additional Required is the difference between the total required and
currently committed resources.
Additional required represents the amount needed to achieve the forecasted
system peak plus a
planning reserve margin.
|
|
|
|
(4)
|
|
Does not include the Ely Energy Center, as the Ely Energy Center is not
expected to be operational until December 2011.
|
NPC includes in its long term plans planning reserves in excess of required operating
reserves.
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 gas-fired generation in the region subjects power prices to gas price volatilities.
NPC faces load obligation uncertainty due to the potential for customer switching. Some
counterparties in these areas have significant credit difficulties, representing credit risk to
NPC. Finally, NPC’s credit standing may affect the terms or ability to enter into certain
transactions.
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.
7
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 2006, NPC
generated approximately 54.3% of its total electric energy requirements, purchasing the remaining
45.7% as shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
MWh
|
|
% of Total
|
|
MWh
|
|
% of Total
|
|
MWh
|
|
% of Total
|
|
NPC Company Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas/Oil
|
|
|
8,093,020
|
|
|
|
36.1
|
%
|
|
|
2,465,064
|
|
|
|
11.7
|
%
|
|
|
2,557,166
|
|
|
|
12.3
|
%
|
|
Coal
|
|
|
4,067,209
|
|
|
|
18.2
|
%
|
|
|
5,629,139
|
|
|
|
26.9
|
%
|
|
|
5,913,062
|
|
|
|
28.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Generated
|
|
|
12,160,229
|
|
|
|
54.3
|
%
|
|
|
8,094,203
|
|
|
|
38.6
|
%
|
|
|
8,470,228
|
|
|
|
40.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hydro
|
|
|
465,983
|
|
|
|
2.0
|
%
|
|
|
409,309
|
|
|
|
2.0
|
%
|
|
|
450,086
|
|
|
|
2.2
|
%
|
|
Spot, Firm and Non-Firm
|
|
|
7,453,758
|
|
|
|
33.3
|
%
|
|
|
10,301,589
|
|
|
|
49.0
|
%
|
|
|
9,458,794
|
|
|
|
45.5
|
%
|
|
Non-Utility Purchases
|
|
|
2,328,653
|
|
|
|
10.4
|
%
|
|
|
2,183,484
|
|
|
|
10.4
|
%
|
|
|
2,410,381
|
|
|
|
11.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Purchased
|
|
|
10,248,394
|
|
|
|
45.7
|
%
|
|
|
12,894,382
|
|
|
|
61.4
|
%
|
|
|
12,319,261
|
|
|
|
59.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total System
|
|
|
22,408,623
|
|
|
|
100.0
|
%
|
|
|
20,988,585
|
|
|
|
100.0
|
%
|
|
|
20,789,489
|
|
|
|
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 2006 company generated MWhs
increased 50.2% from NPC’s 2005 company generated MWhs. The increase in NPC’s generation in 2006
is primarily due to the purchase of a 75% ownership in the SilverHawk generating station and the
addition of the Lenzie generating station. NPC’s 2006 purchased power MWhs decreased 20.5% from
NPC’s 2005 purchased power MWhs. See Energy Supply in Management’s Discussion and Analysis of
Financial Condition and Results of Operations for additional information regarding NPC’s purchasing
strategies.
Risk Management
See Item 7A, Quantitative and Qualitative Disclosures About Market Risk.
Generation
NPC’s generation capacity consists of a combination of 27 gas, oil and coal generating units
with a combined capacity of 3,148 MWs as described in Item 2, Properties. In 2006, NPC generated
approximately 54.3% of its total system requirements.
As described earlier, in an effort to reduce reliance on purchased power and diversify energy
resources NPC acquired the Lenzie generating plant and a 75% ownership interest in the Silverhawk
generating plant. The combination of the two plants added approximately 1,669 MWs of capacity in
2006. Additionally in 2006, NPC added a second 84 MW unit at the Harry Allen generating plant.
The increase in capacity was partially offset by the loss of 403 MW of capacity due to the
retirement of three steam units at the Clark Plant and the shut-down of the Mohave Plant on
December 31, 2005, of which NPC is a 14% owner. See Note 13, Commitments and Contingencies, of the
Notes to the Financial Statements, in Item 8 for further discussion of the Mohave shut-down.
In November, 2006, the PUCN approved Phase 1 of the construction of the Ely Energy Center.
The Ely Energy Center consists of two 750-megawatt coal fired generation units. The first unit is
expected to become operational in late 2011 and the second within three years thereafter. The plan
also includes further expansion possibilities involving two 500 MW coal gasification units when the
technology becomes commercially viable.
Also approved by the PUCN was NPC’s request to construct natural gas-fired combustion turbine
peaking units at Clark Station with approximately 413 MWs of peaking capacity to be installed prior
to the summer of 2008 and approximately 206 MWs of additional peaking capacity to be installed
prior to the summer of 2009.
8
Fuel Availability
NPC’s 2006 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 million British thermal
units (MMBtu) for the years 2002-2006, 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
|
|
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
|
%
|
|
2003
|
|
|
5.70
|
|
|
|
40.9
|
%
|
|
|
1.41
|
|
|
|
59.0
|
%
|
|
|
5.28
|
|
|
|
0.1
|
%
|
|
2002
|
|
|
5.41
|
|
|
|
38.9
|
%
|
|
|
1.37
|
|
|
|
60.9
|
%
|
|
|
5.77
|
|
|
|
0.2
|
%
|
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 gas prices are set at an appropriate industry index during the month of current
delivery. Monthly and daily gas supply adjustments are made by Gas Trading personnel based on the
current energy marketplace. The addition of the Lenzie, Silverhawk and Harry Allen units during
2006 resulted in an increase of company generation. These generating units had the effect of
reducing NPC’s exposure to fluctuations in the market price of gas because 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 2007 since these generating units will be available for the
entire year and NPC has made operating improvements at all sites.
Coal delivered to the Reid Gardner Station originates from various mines in the Utah and
Colorado coal fields and is delivered to the station via the Union Pacific Railroad. NPC had five
coal contracts which expired on December 31, 2006. These contracts were with Canyon Fuel Company,
LLC, a subsidiary of Arch Coal Company, Arch Coal Sales Company, Oxbow Carbon & Minerals, LLC,
Andalex Resources, Inc., and Valmy. They provided the full requirements of coal for 2006. During
2006 NPC executed replacement coal supply agreements effective January 2007. These contracts are
with Arch Coal Sales Company and Andalex Resources, Inc. and will provide 100%, 75%, 45%, and 30%
of Reid Gardner’s projected coal requirements for the years 2007, 2008, 2009, and 2010,
respectively.
As of December 31, 2006, Reid Gardner Station’s coal inventory level was 397,033 tons, or
approximately 66 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
Station in Moapa, Nevada. This contract expires on December 31, 2007.
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. Both of NPC’s rail transportation
contracts contain certain tonnage requirements and railroad service criteria.
Coal for the Navajo Station is obtained from surface mining operations conducted by Peabody
Coal Company (Peabody) on portions of the Black Mesa in Arizona within the Navajo and Hopi Indian
tribes (the Tribes) reservations. The Navajo 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 Energy Supply Plan, 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 2006, NPC purchased 45.7%
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.
9
NPC has entered into long term purchase power contracts (3 or more years) with the following
counterparties:
|
|
|
|
|
|
|
|
|
|
|
Company Name
|
|
|
|
|
|
(Counterparty)
|
|
Quantity (MW)
|
|
Contract Termination
|
|
State of Nevada, Colorado River
Commission
|
|
200 MW
|
|
|
2017
|
|
|
Nevada Sun Peak Limited Partnership
|
|
222 MW
|
|
|
2016
|
|
|
Las Vegas Cogeneration II
|
|
224 MW
|
|
|
2013
|
|
|
Southern Nevada Water Authority
|
|
125 MW
|
|
|
2013
|
|
|
California Department of Water
Resources
|
|
233 MW
|
|
|
2013
|
|
|
Mirant
|
|
200 MW
|
|
|
2008
|
|
|
Mirant
(1)
|
|
100 MW
|
|
|
2007
|
|
|
Mirant
(1)
|
|
25 MW
|
|
|
2007
|
|
|
|
|
|
|
(1)
|
|
Effective from June 15
th
through September 15
th
each year.
|
NPC’s credit standing affects the terms under which NPC is able to purchase fuel and
electricity in the western energy markets. As a result of NPC’s improved credit quality, during
2006 NPC was able to eliminate cash deposits held by counterparties for the purchase of fuel and
electricity, reduce pre-payments for fuel to four counterparties, and reduce the number of
counterparties requiring modified payment terms from the previous year. In early 2007, as further
evidence of improving credit quality, NPC’s electric counterparties eliminated the requirement that
NPC pre-pay electric purchases.
NPC is a member of the Western Systems Power Pool (WSPP) and the Southwest Reserve Sharing
Group (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.
Qualifying Facilities
Federal regulations, including the Public Utility Regulatory Policies Act of 1978 (PURPA),
which were passed to promote renewable and alternative energy resources, and the Energy Policy Act
of 2005, set out the requirements for utilities to purchase the output produced by Qualifying
Facilities (QFs) at costs determined by the appropriate state’s public utility commission. QFs are
small renewable energy power producers and co-generators. Certain QFs can qualify as renewable
resources required by state law as discussed below; however, none of NPC’s current QFs qualify.
As of December 31, 2006, NPC had a total of 305 MW of contractual firm and non-firm capacity
under contract with QFs. In 2006, energy purchased by NPC from the QFs constituted 22.7% of NPC’s
net purchased power requirements for native load and 10.4% of NPC’s net system requirements
(including generation).
Renewable Energy
Nevada law sets forth the renewable energy portfolio standard (“Portfolio Standard”) requiring
providers of electric service to acquire, generate, or save a specific percentage of its energy
from renewable energy resources (Renewables). Renewables include, but are not limited to:
biomass, geothermal, solar and wind projects. Pursuant to the Portfolio Standard, NPC was required
to obtain six percent of its total energy from Renewables for year 2006. The Portfolio Standard
increases by three percent (3%) every other year until it reaches 20% in year 2015. In addition,
the Portfolio Standard allows energy efficiency measures from qualified conservation programs to
meet up to 25% of the Portfolio Standard. Moreover, not less than five percent (5%) of the total
Portfolio Standard must be met from solar resources.
Nevada law also requires providers of electric services to file an annual report that
describes the level of compliance with the Portfolio Standard. In its April 2006 Portfolio
Standard Annual Report for Compliance Year 2005, NPC reported that with PUCN approval of a sale and
purchase of SPPC’s excess non-solar portfolio energy credits (“PCs”), NPC would meet the non-solar
Portfolio Standard. However, NPC was non-compliant with the solar portion of the Portfolio
Standard in 2005. Additionally, the report described NPC’s ongoing activities to reach full
compliance with the Portfolio Standard in the near future. NPC will be required to meet nine
percent (9%) of its total energy from Renewables for years 2007 and 2008.
NPC’s IRP approved by the PUCN in November, included NPC’s three-year Action Plan for
acquiring Renewables and developing renewable energy facilities. In addition, in January 2007, the
PUCN approved NPC’s Portfolio Standard Annual Report for Compliance Year 2005 and granted its
request for the purchase of SPPC’s excess non-solar PCs and granted an exemption from the solar
portion of the Portfolio Standard for compliance year 2005.
10
In April 2007, NPC will file with the PUCN its Portfolio Standard Annual Report for Compliance
Year 2006. NPC expects it will meet the non-solar Portfolio Standard, but may not meet the solar
requirement for 2006. If so, NPC will request an exemption from the PUCN for the solar portion of
the Portfolio Standard for calendar year 2006.
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 Western
Electric Coordinating Council (WECC). WECC is one of ten regional councils of the North American
Electric Reliability Council, the entity responsible for the reliability, adequacy and security of
North America’s bulk electric system.
NPC’s transmission system links generating units within the NPC control area and generating
systems, located external to the NPC control 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 Ely Energy Center
includes a 500 kV line that will interconnect the transmission systems of the two companies by
2011. The map below shows NPC’s transmission system:
As the control area operator, NPC is responsible for continuously balancing electric supply
and demand by monitoring and controlling generating resources and interchange transactions so that
generation internal to the control area plus net import power matches control area load. NPC also
schedules power deliveries over its transmission system and maintains reliability by verifying that
customers are matching loads with resources.
NPC plans, builds and operates a transmission system that delivered 22,408,623 MWh of
electricity to customers on its transmission system in 2006. The NPC system handled a peak load of
5,623 MW in 2006 through 2,062 circuit miles of transmission
11
lines and other transmission facilities ranging from 60kV to 500kV. 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 high growth system.
In the last 8 years, due primarily to high customer growth, NPC has constructed 4 major
transmission projects totaling 210 miles of high voltage transmission. The projects completed
include River Mountain (40 miles), Crystal (10 miles), Bighorn (60 miles), and Centennial (100
miles).
Transmission Regulatory Environment
NPC’s wholesale and retail access transmission services are regulated by the FERC under cost
based regulation subject to the SPR Operating Companies Open Access Transmission Tariff (OATT).
Transmission for NPC’s bundled retail customers is subject to the jurisdiction of the PUCN for rate
making purposes. In accordance with the OATT, NPC offers several transmission services to
wholesale customers:
|
|
•
|
|
Long-term and short-term firm point-to-point transmission service (“guaranteed” 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 generating and marketing business in
accordance with FERC Standards of Conduct.
NPC is participating in the development of WestConnect. 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 November 2005, NPC
discontinued its relationship with Grid West and joined WestConnect as a member.
Construction Program
NPC’s construction program and estimated expenditures are subject to continuing review, and
are 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, adequacy of rate relief, 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 2006, including allowance for funds used during
construction (AFUDC), net salvage, and contributions in aid of construction, were $670.4 million,
and for the period 2002 through 2006, were $2.2 billion. Estimated construction expenditures for
2007 and the period from 2008 to 2011 are as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008-2011
|
|
|
5 - Year
|
|
|
Electric Facilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
$
|
537,998
|
|
|
$
|
3,082,351
|
|
|
$
|
3,620,349
|
|
|
Distribution
|
|
|
211,551
|
|
|
|
888,550
|
|
|
|
1,100,101
|
|
|
Transmission
|
|
|
140,041
|
|
|
|
1,103,075
|
|
|
|
1,243,116
|
|
|
Other
|
|
|
136,438
|
|
|
|
403,882
|
|
|
|
540,320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,026,028
|
|
|
$
|
5,477,858
|
|
|
$
|
6,503,886
|
|
|
|
|
|
|
|
|
|
|
|
|
12
Total estimated construction and plant cash requirements related to construction projects
for 2007 and the 2008 to 2011 period consist of the following (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008-2011
|
|
|
Total 5 - Year
|
|
|
Construction Expenditures
|
|
$
|
1,026,028
|
|
|
$
|
5,477,858
|
|
|
$
|
6,503,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AFUDC
|
|
|
(23,373
|
)
|
|
|
(487,761
|
)
|
|
|
(511,134
|
)
|
|
Net Salvage/ Cost of Removal
|
|
|
(1,800
|
)
|
|
|
(7,400
|
)
|
|
|
(9,200
|
)
|
|
Net Customer Advances and CIAC
|
|
|
(20,800
|
)
|
|
|
(85,305
|
)
|
|
|
(106,105
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash Requirements
|
|
$
|
980,055
|
|
|
$
|
4,897,392
|
|
|
$
|
5,877,447
|
|
|
|
|
|
|
|
|
|
|
|
|
In
November, 2006 the PUCN approved NPC’s IRP, which among other items, includes
the approval of Phase 1 construction of the Ely Energy Center. The PUCN approved spending up to
$300 million for development activities associated with Ely Energy Center with a limitation of $155
million placed on expenditures until the Utilities’ have obtained appropriate air permits. Current
estimates to construct the Ely Energy Center, which includes a 500KV transmission line to connect
NPC’s and SPPC’s transmission systems is approximately $3.8 billion. NPC’s estimated 80%
allocation of the Ely Energy Center is included in construction expenditures above. The PUCN also
required that NPC file an amendment to its 2006 IRP in early 2008 once elements of the plan,
including final costs, can be more accurately estimated.
Also included in the approval of the IRP was NPC’s request to construct natural gas-fired
combustion turbine peaking units at Clark Station at a cost of approximately $395 million with
approximately 413 MWs of peaking capacity to be installed prior to the summer of 2008 and
approximately 206 MWs of additional peaking capacity to be installed prior to the summer of 2009.
SIERRA PACIFIC POWER COMPANY
A Nevada corporation since 1965, SPPC was originally incorporated in Maine in 1912. SPPC
became a subsidiary of SPR 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, Piñon Pine Corp. (PPC) and Piñon Pine Investment Co. (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 361,000 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
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.
To serve its growing customer base, SPPC purchases power and generates electricity in
accordance with an Energy Supply Plan, 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. SPPC’s strategy is to grow its generating capacity in an effort to reduce reliance
on purchased power. As part of this strategy, SPPC is constructing a 514 MW gas-fired
combined-cycle plant at Tracy, east of Reno. The plant is scheduled to be completed by the summer
of 2008. Additionally, in November 2006, the PUCN approved SPPC’s thirteenth amendment to its 2004
IRP. Included in the PUCN’s approval is the Ely Energy Center.
Electric loads and resulting revenues are affected by customer growth, weather, rate changes,
and customer usage patterns. SPPC’s revenues and associated expenses are not incurred or generated
evenly throughout the year.
13
Nevada regulations require SPPC to file general rate cases every two years with the PUCN to
adjust rates including cost of service and return on investment. Nevada state regulations also
require SPPC to make annual filings to reset BTER and either recover or credit deferred energy
balances that include fuel and purchased power costs above or below amounts collected in current
retail rates. If necessary, SPPC can file more frequently than once a year to seek a change in
BTER to more closely match actual prices. 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.
Under federal law, wholesale rates charged by SPPC are subject to certain jurisdictional
regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with
respect to 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 takes service.
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.
In December 2005, Barrick Gold (Barrick), a large SPPC mining customer, concluded its
construction of a 118 MW generating facility to meet the majority of its electric power needs.
Barrick continues to purchase transmission and distribution services from SPPC and is selling
approximately 8 MW of capacity from its new generating facility to SPPC. Barrick MWh retail sales
for 2005 were approximately 10.1% of total system sales for SPPC.
Newmont Mining Corporation (Newmont) is constructing a new 203 MW generating plant in
northeastern Nevada which is anticipated to be operational in 2008. In 2004, SPPC and Newmont
entered into a nonbinding Term Sheet that provides for a wholesale power sale agreement and a new
form of retail service. Under the term sheet, Newmont would sell the electrical output from its
plant to SPPC for at least 15 years under a 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 a new rate schedule. SPPC and Newmont submitted a number of related
filings to the PUCN which were approved on February 23, 2005.
Currently, there are no other material applications pending with the PUCN to exit the system
in SPPC’s service territory.
Sales
In 2006, SPPC set approximately 9,950 meters and forecasts that it will set over 9,000 meters
in 2007. In 2006, SPPC’s electric operations contributed approximately $1.0 billion, or 83%, of
SPPC’s total revenues.
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 peak load increased at an average annual growth rate of 2.2% over the past five
years, reaching 1,701 MW in July 2006.
14
SPPC’s electric customers by class contributed the following toward 2006, 2005 and 2004 MWh
sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWH Sales (Billed and Unbilled)
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
2,480,681
|
|
|
|
28.2
|
%
|
|
|
2,381,389
|
|
|
|
25.5
|
%
|
|
|
2,295,944
|
|
|
|
23.8
|
%
|
|
Commercial and
Industrial:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mining
|
|
|
1,873,177
|
|
|
|
21.3
|
%
|
|
|
2,716,309
|
|
|
|
29.1
|
%
|
|
|
2,686,716
|
|
|
|
27.8
|
%
|
|
All Other
|
|
|
4,356,878
|
|
|
|
49.5
|
%
|
|
|
4,136,208
|
|
|
|
44.3
|
%
|
|
|
4,160,567
|
|
|
|
43.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Retail
|
|
|
8,710,736
|
|
|
|
99.0
|
%
|
|
|
9,233,906
|
|
|
|
98.9
|
%
|
|
|
9,143,227
|
|
|
|
94.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale
|
|
|
69,757
|
|
|
|
0.8
|
%
|
|
|
81,856
|
|
|
|
0.9
|
%
|
|
|
505,986
|
|
|
|
5.2
|
%
|
|
Streetlights
|
|
|
15,502
|
|
|
|
0.2
|
%
|
|
|
15,105
|
|
|
|
0.2
|
%
|
|
|
14,932
|
|
|
|
0.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
|
8,795,995
|
|
|
|
100
|
%
|
|
|
9,330,867
|
|
|
|
100
|
%
|
|
|
9,664,145
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2006, mining MWh sales decreased significantly due to the departure of Barrick which
represented approximately 10.1% of total system sales in 2005. However, Nevada’s precious metals
mining industry continued to see positive developments as the spot price of gold on world markets
increased in 2006 by 19%, from $530 per ounce on January 3, 2006 to $632 per ounce on December 28,
2006, as reported by Kitco.com. . This increase in price, coupled with Nevada’s reasonable
regulatory environment and favorable geology for gold deposits, offers positive opportunities for
future mine development. Given the substantial amounts of both proven and probable gold reserves
at existing mining operations and the industry’s strong presence in the state, the mining
industry’s resulting high energy usage is expected to continue into the future, assuming that gold
prices stay high.
SPPC has long-term electric service agreements with six of its major mining customers, with
yearly revenues under these agreements totaling approximately $94.7 million. For 2006, this
represented 9.3% of SPPC’s electric operating revenues of $1.0 billion. These 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.
In 2005, MWh sales in the wholesale segment decreased by 83.8% compared to sales in 2004.
This decrease was a result of market conditions that resulted in fewer economic opportunities in
layoffs/swap sales and purchases in 2005 compared to 2004. In addition, certain types of
transactions that were reported in sales for 2004 are now being netted in purchased power.
Demand
Load and Resources Forecast
SPPC’s integrated peak electric demand dropped from 1,740 MW in 2005 to 1,701 MW in 2006
mainly due to the Barrick departure from SPPC’s system. Variations in energy usage by SPPC’s
customers occur as a result of varying weather conditions and other energy usage behaviors. 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. As discussed in Energy Supply – Generation, SPPC is constructing a new 514 MW
Combined Cycle facility at the existing Tracy Generating Station with a scheduled in-service date
of June 2008. The addition of this facility is expected to significantly reduce SPPC’s reliance
on purchased power compared to prior years. Remaining needs will be met through power purchased
through RFPs or short term purchases.
15
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)
|
|
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
(4)
|
|
Total Requirements (1)
|
|
|
1,870
|
|
|
|
2,051
|
|
|
|
2,134
|
|
|
|
2,177
|
|
|
|
2,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resources:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company-owned existing generation
|
|
|
1,023
|
|
|
|
1,023
|
|
|
|
1,035
|
|
|
|
1,035
|
|
|
|
1,035
|
|
|
Company-owned new generation (2)
|
|
|
|
|
|
|
514
|
|
|
|
514
|
|
|
|
514
|
|
|
|
514
|
|
|
Contracts for power purchases
|
|
|
847
|
|
|
|
257
|
|
|
|
213
|
|
|
|
261
|
|
|
|
279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currently Committed Resources
|
|
|
1,870
|
|
|
|
1,794
|
|
|
|
1,762
|
|
|
|
1,810
|
|
|
|
1,828
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional Required (3)
|
|
|
—
|
|
|
|
257
|
|
|
|
372
|
|
|
|
367
|
|
|
|
383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Includes system peak load plus planning reserves.
|
|
|
|
(2)
|
|
New generation in 2008 for Tracy combined cycle facility at 514 MW.
|
|
|
|
(3)
|
|
Additional Required represents the difference between the current committed
resources and the
total resources needed to achieve the forecasted system peak plus a planning
reserve margin.
|
|
|
|
(4)
|
|
Does not include the Ely Energy Center, as the Ely Energy Center is not
expected to be operational until December 2011.
|
SPPC includes in its long term plans planning reserves in excess of required operating
reserves.
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 gas-fired generation in the service territory subjects power prices to gas price
volatilities. SPPC faces load obligation uncertainty due to the potential for customer switching.
Some counterparties in these areas have significant credit difficulties, representing credit risk
to SPPC. Finally, SPPC’s credit standing may affect the terms or ability to enter into certain
transactions.
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.
16
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 2006, SPPC
generated 43.1% of its total electric energy requirements, purchasing the remaining 56.9% as shown
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
MWh
|
|
% of Total
|
|
MWh
|
|
% of Total
|
|
MWh
|
|
% of Total
|
|
SPPC Company Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas/Oil
|
|
|
2,210,532
|
|
|
|
23.4
|
%
|
|
|
2,345,196
|
|
|
|
23.9
|
%
|
|
|
2,562,103
|
|
|
|
24.8
|
%
|
|
Coal
|
|
|
1,848,591
|
|
|
|
19.7
|
%
|
|
|
2,000,719
|
|
|
|
20.4
|
%
|
|
|
2,018,715
|
|
|
|
19.6
|
%
|
|
Hydro
|
|
|
0
|
|
|
|
N/A
|
|
|
|
33,355
|
|
|
|
0.3
|
%
|
|
|
24,090
|
|
|
|
0.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Generated
|
|
|
4,059,123
|
|
|
|
43.1
|
%
|
|
|
4,379,270
|
|
|
|
44.6
|
%
|
|
|
4,604,908
|
|
|
|
44.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spot, Firm and Non-Firm
|
|
|
4,392,896
|
|
|
|
46.8
|
%
|
|
|
4,778,786
|
|
|
|
48.7
|
%
|
|
|
4,845,650
|
|
|
|
46.9
|
%
|
|
Non-Utility Purchases
|
|
|
941,445
|
|
|
|
10.1
|
%
|
|
|
662,261
|
|
|
|
6.7
|
%
|
|
|
873,868
|
|
|
|
8.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Purchased
|
|
|
5,334,341
|
|
|
|
56.9
|
%
|
|
|
5,441,047
|
|
|
|
55.4
|
%
|
|
|
5,719,518
|
|
|
|
55.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total System
|
|
|
9,393,464
|
|
|
|
100.0
|
%
|
|
|
9,820,317
|
|
|
|
100.0
|
%
|
|
|
10,324,426
|
|
|
|
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. The decrease in total system was primarily
due to the transition of Barrick to a distribution only services customer in 2006. SPPC’s 2006
company generation decreased 7.3% compared to 2005. SPPC’s 2006 purchased power total MWhs
decreased 2.0% from SPPC’s 2005 purchased power MWhs. 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 24 gas, oil and coal generating units
with a combined capacity of 1,043 MWs as described in Item 2, Properties. In 2006, SPPC generated
approximately 43.1% of its total system requirements.
In an effort to reduce reliance on purchased power and diversify energy resources, SPPC is
constructing a 514 MW gas fired combined cycle generator at the Tracy station. The unit is
expected to be operable by June 2008.
In November, 2006, the PUCN approved SPPC’s Phase 1 of the construction of the Ely Energy
Center. The Ely Energy Center consists of two 750-megawatt coal fired generation units. The first
unit is expected to become operational in late 2011 and the second within three years thereafter.
The plan also includes further expansion possibilities involving two 500 MW coal gasification units
when the technology becomes commercially viable.
17
Fuel Availability
SPPC’s 2006 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
2002-2006, 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
|
|
2006
|
|
|
8.92
|
|
|
|
55.85
|
%
|
|
|
1.83
|
|
|
|
43.88
|
%
|
|
|
10.15
|
|
|
|
.27
|
%
|
|
2005
|
|
|
7.87
|
|
|
|
56.81
|
%
|
|
|
1.67
|
|
|
|
43.08
|
%
|
|
|
7.37
|
|
|
|
.11
|
%
|
|
2004
|
|
|
7.32
|
|
|
|
53.11
|
%
|
|
|
1.39
|
|
|
|
44.93
|
%
|
|
|
6.14
|
|
|
|
1.96
|
%
|
|
2003
|
|
|
6.68
|
|
|
|
59.11
|
%
|
|
|
1.60
|
|
|
|
40.79
|
%
|
|
|
6.92
|
|
|
|
.10
|
%
|
|
2002
|
|
|
4.42
|
|
|
|
41.10
|
%
|
|
|
1.68
|
|
|
|
58.70
|
%
|
|
|
5.69
|
|
|
|
.20
|
%
|
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 gas prices are set at an appropriate industry index during the month of current
delivery. Monthly and daily gas supply adjustments are made by Gas Trading personnel based on the
current energy marketplace.
SPPC has long-term coal contracts with Arch Coal Sales Company and Black Butte Coal Company
that provide for deliveries through December 31, 2009. These contracts represent 100% of Valmy’s
projected coal requirements in 2007, and 75% of Valmy’s projected coal requirements for 2008 and
2009.
Union Pacific Railroad originates and delivers coal to the Valmy station. A transportation
services contract is in place that expires December 31, 2007.
As of December 31, 2006, Valmy’s coal inventory level was 354,103 tons or approximately 62
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.
Purchased Power
SPPC, under the guidelines set forth in the SPPC Energy Supply Plan, 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 2006, SPPC purchased 56.9%
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) with the following
counterparties:
|
|
|
|
|
|
|
Energy Provider
|
|
Capacity
|
|
Expiration
|
|
Pacificorp
|
|
75 MW
|
|
2009
|
|
Barrick
|
|
8 MW
|
|
2008
|
SPPC’s credit standing affects the terms under which SPPC is able to purchase fuel and
electricity in the western energy markets. As a result of SPPC’s improved credit quality, during
2006 SPPC was able to eliminate cash deposits held by counterparties for the purchase of fuel and
electricity; reduce pre-payments for fuel to four counterparties; and reduce the number of
counterparties requiring modified payment terms from the previous year. In early 2007 as further
evidence of improving credit quality, SPPC’s electric counterparties eliminated the requirement
that SPPC pre-pay electric purchases.
18
SPPC is a member of the Northwest Power Pool and Western Systems Power Pool. 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.
Qualifying Facilities
Federal regulations, including the Public Utility Regulatory Policies Act of 1978 (PURPA),
which were passed to promote renewable and alternative energy resources, and the Energy Policy Act
of 2005 set out the requirements for utilities to purchase the output produced by Qualifying
Facilities (QFs) at costs determined by the appropriate state’s public utility commission. QFs are
small renewable energy power producers and co-generators. Certain QFs can qualify as renewable
resources required by state law as discussed below.
As of December 31, 2006, SPPC had a total of 151 MW of contractual firm and non-firm capacity
under contract with QFs. In 2006, energy purchased by SPPC from the QFs constituted 17.4% of
SPPC’s net purchased power requirements for native load and 9.9% of SPPC’s net system requirements
(including generation).
Renewable Energy
Nevada law sets forth the Portfolio Standard requiring providers of electric service to
acquire, generate, or save a specific percentage of its energy from Renewables. Renewables include,
but are not limited to: biomass, geothermal, solar and wind projects. Pursuant to the Portfolio
Standard, SPPC was required to obtain six percent of its total energy from Renewables for year
2006. The Portfolio Standard increases by three percent (3%) every other year until it reaches 20
percent in year 2015. In addition, the Portfolio Standard allows energy efficiency measures from
qualified conservation programs to meet up to 25 percent of the Portfolio Standard. Moreover, not
less than five percent (5%) of the total Portfolio Standard must be met from solar resources.
Nevada law also requires providers of electric services to file an annual report that
describes the level of compliance with the Portfolio Standard. In its April 2006 Portfolio
Standard Annual Report for Compliance Year 2005, SPPC reported compliance with the non-solar
Portfolio Standard. However, SPPC was non-compliant with the solar portion of the Portfolio
Standard in 2005. Additionally the report described SPPC’s ongoing activities to reach full
compliance with the Portfolio Standard in the near future. SPPC will be required to meet nine
percent (9%) of its total energy from Renewables for years 2007 and 2008.
In August 2006, the PUCN approved a long-term power purchase agreement for supply of renewable
energy and portfolio energy credits (“PCs”) to SPPC from a project known as Galena 3 Geothermal
Project being developed by Ormat Nevada, Inc.
In January 2007, the PUCN approved SPPC’s Portfolio Standard Annual Report for Compliance Year
2005 and granted its request for an exemption from the solar portion of the Portfolio Standard for
compliance year 2005.
In April 2007, SPPC will file with the PUCN its Portfolio Standard Annual Report for
Compliance Year 2006. SPPC expects it will meet the non-solar Portfolio Standard, but may not meet
the solar requirement for 2006. If so, SPPC will request an exemption from the PUCN for the solar
portion of the Portfolio Standard for calendar year 2006.
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 Western
Electric Coordinating Council (WECC). WECC is one of ten regional councils of the North American
Electric Reliability Council, 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 control 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 Ely Energy Center includes a 500 kV
line that will interconnect the transmission systems of the two companies by 2011. The map below
shows SPPC’s transmission system:
19
As the control area operator, SPPC is responsible for continuously balancing electric supply
and demand by monitoring and controlling generating resources and interchange transactions so that
generation internal to the control area plus net import power matches control area load. SPPC
also schedules power deliveries over its transmission system and maintains reliability by verifying
that customers are matching loads with resources.
SPPC plans, builds and operates a transmission system that delivered 9,393,464 MWh of
electricity to customers in its control area in 2006. The SPPC system handled a peak load of 1,701
MW in 2006 through 2,446 circuit miles of transmission lines and other facilities ranging from 60kV
to 345kV. 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 fast growing
system.
In the last 8 years, due primarily to high customer growth, SPPC has constructed 2 major
transmission projects totaling 347 miles of high voltage transmission. The projects completed
include Alturas (167 miles), and Falcon – Gonder (180 miles).
Transmission Regulatory Environment
SPPC’s wholesale and retail access transmission services are regulated by the FERC under cost
based regulation subject to the SPR Operating Companies Open Access Transmission Tariff (OATT).
Transmission for SPPC’s bundled retail customers is subject to the jurisdiction of the PUCN for
rate making purposes. In accordance with the OATT, SPPC offers several transmission services to
wholesale customers:
|
|
•
|
|
Long-term and short-term firm point-to-point transmission service (“guaranteed” 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).
|
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 generating and marketing business in
accordance with FERC Standards of Conduct.
20
SPPC is participating in the development of WestConnect. 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 early 2006, SPPC
discontinued its relationship with Grid West and joined WestConnect as a member.
SPPC Gas
Business and Competitive Environment
Overview
SPPC provides natural gas service to approximately 146,000 customers in an area of about 600
square miles in Nevada’s Reno/Sparks area. SPPC also procures natural gas for electric power
generation at the Tracy and Fort Churchill plants 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 71 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 send-out to vary substantially from a warm
summer day to a cold winter day.
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
have been somewhat 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 primary fuel
source.
To serve its growing customer base, SPPC purchases all of its natural gas supply. 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: Paiute Pipeline Company and Tuscarora Gas Transmission. 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 Plan to be filed annually. Natural gas commodity
costs are passed directly through to customers on a dollar for dollar basis. SPPC does not profit
from increased natural gas prices. SPPC may also file general rate cases 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 local distribution company (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 (INGR) 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, 2007, there were 15 large customers securing their own supplies.
These customers have a combined firm distribution load of approximately 4,940 Decatherms (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.
Revenue
SPPC’s natural gas business accounted for $210 million in 2006 operating revenues or 17% of
SPPC’s total revenues from continuing operations. SPPC expects to install approximately 5,000
meters in 2007.
Demand
Growth in all sectors is expected to continue as a result of new real estate developments
under construction and planned for the near future in SPPC’s distribution service area. Projected
peak demand, which will only occur when the temperature drops to 3 degrees Fahrenheit, is estimated
to be 193,500 Dth for the winter of 2006/2007, up from 187,000 Dth for the previous winter.
21
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. Seasonal and
monthly gas supply contracts averaged approximately 116,000 Dth per day with the winter period
contracts averaging approximately 134,000 Dth per day, and the summer period contracts averaging
approximately 103,000 Dth per day.
SPPC’s firm natural gas supply is supplemented with natural gas storage services and supplies
from a Northwest Pipeline Co. facility located at Jackson Prairie in southern Washington. The
Jackson Prairie facility contributed a total of 12,687 Dth per day of peaking supplies. SPPC also
has storage on the Paiute Pipeline system. This liquefied gas storage project 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, 2006:
Firm Transportation Capacity
|
|
|
|
|
|
|
|
|
|
|
Northwest
|
|
|
68,664
|
|
|
decatherms per day firm
|
|
(Annual)
|
|
Paiute
|
|
|
68,696
|
|
|
decatherms per day firm
|
|
(November through March)
|
|
Paiute
|
|
|
61,044
|
|
|
decatherms per day firm
|
|
(April through October)
|
|
Paiute
|
|
|
23,000
|
|
|
decatherms per day firm
|
|
(LNG tank to Reno/Sparks)
|
|
Nova
|
|
|
130,217
|
|
|
decatherms per day firm
|
|
(Annual)
|
|
ANG
|
|
|
128,932
|
|
|
decatherms per day firm
|
|
(Annual)
|
|
GTN
|
|
|
130,169
|
|
|
decatherms per day firm
|
|
(November through April)
|
|
GTN
|
|
|
69,899
|
|
|
decatherms per day firm
|
|
(May through October)
|
|
Tuscarora
|
|
|
132,823
|
|
|
decatherms per day firm
|
|
(Annual)
|
Storage Capacity
|
|
|
|
|
|
|
|
|
Williams:
|
|
|
281,242
|
|
|
decatherms inventory capability at Jackson Prairie
|
|
|
|
|
12,687
|
|
|
decatherms withdrawal capability per day from Jackson Prairie
|
|
Paiute
|
|
|
303,604
|
|
|
Decatherms inventory capability at Paiute LNG
|
|
|
|
|
23,000
|
|
|
LNG Storage
|
Total LDC Dth supply requirements in 2006 and 2005 were 15.5 million Dth and 17.1 million
Dth, respectively. Electric generating fuel requirements for 2006 and 2005 were 23.5 million Dth
and 24.3 million Dth, respectively.
Gas Distribution
As of December 31, 2006, SPPC owned and operated 1,988 miles of three-inch equivalent natural
gas distribution piping. SPPC constructed approximately 2,600 feet of 12” steel gas main in the
Stead area in 2006. SPPC also continued to increase its ongoing main and service replacement
projects by replacing approximately 10,700 feet of various sized sections of main and approximately
124 services in 2006.
SPPC Electric and Gas
Construction Program
SPPC’s construction program and estimated expenditures are subject to continuing review and
are 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, adequacy of rate relief, 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.
22
SPPC’s
gross construction expenditures for 2006, including AFUDC and contributions in aid of
construction, were $316 million, and for the period 2002 through
2006, were $844 million.
Estimated construction expenditures for 2007 and the period 2008-2011 are as follows (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008-2011
|
|
|
5 - Year
|
|
|
Electric Facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
$
|
309,256
|
|
|
$
|
871,233
|
|
|
$
|
1,180,489
|
|
|
Distribution
|
|
|
61,596
|
|
|
|
262,460
|
|
|
|
324,056
|
|
|
Transmission
|
|
|
54,301
|
|
|
|
328,646
|
|
|
|
382,947
|
|
|
Other
|
|
|
29,258
|
|
|
|
123,852
|
|
|
|
153,110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
454,411
|
|
|
|
1,586,191
|
|
|
|
2,040,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
16,652
|
|
|
|
70,944
|
|
|
|
87,596
|
|
|
Other
|
|
|
80
|
|
|
|
339
|
|
|
|
419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
16,732
|
|
|
|
71,283
|
|
|
|
88,015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Facilities
|
|
|
15,349
|
|
|
|
64,965
|
|
|
|
80,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
486,492
|
|
|
$
|
1,722,439
|
|
|
$
|
2,208,931
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated construction and plant cash requirements for 2007 and the 2008-2011
periods consist of the following (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008-2011
|
|
|
Total 5 - Year
|
|
|
Construction Expenditures
|
|
$
|
486,492
|
|
|
$
|
1,722,439
|
|
|
$
|
2,208,931
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AFUDC
|
|
|
(28,926
|
)
|
|
|
(120,038
|
)
|
|
|
(148,964
|
)
|
|
Net Salvage/ Cost of Removal
|
|
|
(2,800
|
)
|
|
|
(11,465
|
)
|
|
|
(14,265
|
)
|
|
Net Customer Advances and CIAC
|
|
|
(22,000
|
)
|
|
|
(90,230
|
)
|
|
|
(112,230
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash Requirements
|
|
$
|
432,766
|
|
|
$
|
1,500,706
|
|
|
$
|
1,933,472
|
|
|
|
|
|
|
|
|
|
|
|
|
In December 2005, the PUCN approved the construction of a 514-megawatt, combined cycle
natural gas power plant at Tracy Generating Station. Estimated construction costs are approximately
$421 million with completion expected in 2008. Total project cost incurred was $168.9 million as of
December 31, 2006.
In November 2006, the PUCN approved SPPC’s thirteenth amendment to its 2004 IRP, which among
other items includes the approval of Phase 1 construction of the Ely Energy Center. The PUCN
approved spending up to $300 million for development activities associated with Ely Energy Center
with a limitation of $155 million placed on expenditures until the Utilities have obtained
appropriate air permits. Current estimates to construct the Ely Energy Center, which includes a
500KV transmission line to connect NPC and SPPC transmission systems is approximately $3.8 billion.
SPPC’s estimated 20% allocation is included in construction expenditures above.
OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES
Tuscarora Gas Pipeline Company
Tuscarora Gas Pipeline Company (TGPC) was formed in 1993 as a wholly owned subsidiary of SPR
for the purpose of entering into a partnership with a wholly owned subsidiary of TransCanada
PipeLines, Ltd., headquartered in Calgary, Alberta, Canada. The partnership, Tuscarora Gas
Transmission Company (TGTC) owned 50% by TGPC was formed for the purpose of constructing and
operating an interstate natural gas pipeline from Malin, Oregon to Reno, Nevada to serve an
expanding natural gas market in northern Nevada and northeastern California. In November 2006,
TGPC announced that it entered into an agreement to sell its interest in TGTC to TC
PipeLines, LP for $100 million. In December 2006, TC PipeLines, LP assumed TGPC’s
share in the pipeline company.
As an interstate natural gas pipeline, TGTC provides only transportation service to its
customers. SPPC was the only customer at the start of commercial operations in 1995 and while TGTC
serves many other customers today, SPPC continues to be TGTC’s largest customer contributing 71.2%
of gross revenues in 2006.
23
Sierra Pacific Communications
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 and recognized a gain on sale of assets of
approximately $2.5 million (pretax) in connection with the sale of the MAN assets. SPC retained
possession of one duct and associated occupancy rights in the Long Haul System allowing SPC to
complete the transfer and sale of this duct, which was negotiated under a 2002 contract with Qwest
Communications (Qwest) for $20 million. In 2004, in accordance with Statement of Financial
Accounting Standards 144 (SFAS 144),
Accounting for the Disposition or Impairment of Long-Lived
Assets
, SPR reported the remaining Long Haul System as discontinued operations. However, due to
certain legal issues, SPC was delayed in consummating the sale of the Long Haul System to Qwest.
In January 2007, SPC agreed to dismiss pending arbitration against Qwest. As part of the
Settlement Agreement, Qwest agreed to execute a quit claim deed disclaiming any further interest in
the Long Haul system. In accordance with SFAS 144, if at any time the criteria for classifying
assets as held for sale are no longer met, a long-lived asset classified as held for sale shall be
reclassified as held and used. As of December 31, 2006, SPC assets associated with the Long-Haul
were reclassified for all periods presented from assets held for sale in Discontinued Operations to
assets held and used.
Lands of Sierra
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 SPR’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 SPR.
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 (SPR, 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 United States
Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and
Clark County Department of Air Quality and Environmental Management (DAQEM) administer regulations
involving air quality, water pollution, solid, and hazardous and toxic waste. See Note 13,
Commitments and Contingencies, Environmental of the Notes to Financial Statements, for further
discussion.
Federal Legislative and Regulatory Initiatives
The topic of climate change continues to evolve, and response to this issue brings with it
environmental, economic and social implications for SPR and other electric utilities. The United
States currently has no policy or regulation to address 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.
Every generation alternative – whether fossil fuels, nuclear, or renewable power options– has
environmental and financial impacts. SPR recognizes these impacts and
closely links its business
objective of generating reliable, cost-effective energy with its environmental responsibilities.
SPR has and will continue to identify projects that minimize or offset greenhouse gas emissions and
believes precautionary actions to slow greenhouse gas emissions are appropriate. In 2006, SPR
joined the California Climate Action Registry, in which SPR will voluntarily inventory, certify and
publicly report on greenhouse gas emissions from NPC and SPPC by the end of 2007.
SPR’s environmental philosophy accentuates prudent use of natural resources and to that end,
SPR supports multiple program areas aimed at achieving overall air emission reductions. Some
examples are:
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|
•
|
|
Installation of commercially-proven pollution controls coupled with an emphasis on
continued operational excellence to achieve further plant efficiency improvements. SPR’s
new natural gas-fired generating plants require the combustion of far less fuel than
older facilities to produce each kilowatt hour of electrical output. As new
generation is added to the system, SPR is concurrently evaluating and eliminating older, less
efficient units from its fleet.
|
24
|
|
•
|
|
Maintenance of robust demand-side management 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. SPR is reserving space in its proposed Ely Energy
Center design that will allow the retrofit of carbon capture technology once it becomes
commercially viable.
|
|
|
|
|
•
|
|
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 SPR sells
must come from renewable sources, reaching 20 percent by 2015. With
two large-scale solar projects presently under construction in the State, by the end of
2007, Nevada will be number one in the nation for solar watts generated per person and
the percentage of solar to total kilowatt hours sold.
|
SPR and the Utilities may be affected by future federal or state legislation or regulations
mandating a reduction in greenhouse gas emissions. Because of the high level of uncertainty
regarding when any legislation or regulations will be adopted in this area or what form they will
take, management is unable at this time to evaluate the potential economic impact of any such
measures on SPR or the Utilities.
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
would require reductions in emissions of nitrogen oxides, sulfur dioxide and mercury. There is
significant uncertainty at this time as to whether such legislation will be passed by Congress and,
if passed, the timing and extent of any required reductions.
Of particular importance to SPR, in 2005 the EPA issued its Clean Air Mercury Rule (CAMR) and
Regional Haze Rule. SPR notes that both rules have been the subject of litigation by various
parties.
CAMR
— The EPA’s CAMR uses a national cap-and-trade system and is designed to achieve a 70
percent reduction in mercury emissions. It affects all coal and oil-fired generating units across
the country that are greater than 25 megawatts. Compliance with this rule also occurs in two
phases, with the first phase beginning in 2010 and the second phase in 2018. Under the Federal
program, states will be allocated mercury allowances based on coal type and their baseline heat
input relative to other states. Each electric generating unit will be 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. The
State rule was submitted to EPA for approval in late 2006, and is currently pending approval.
Under the Nevada Clean Air Mercury Rule (NV CAMR), existing coal-fired facilities will be
granted allowances for use during Phase I of the compliance period (2010 -2017). New SPR
coal-fired units will be required to meet a specified emission limit and procure sufficient mercury
emission allowances for compliance. SPR’s preliminary analysis of Phase I of the NV CAMR suggests
that several of SPR’s existing units will be eligible to earn extra allowances, which may be
applied to cover emissions from new sources as necessary.
Under Phase II of the compliance period (2018 and beyond), is it not certain whether or not
SPR will be allotted the required allowances to cover its mercury emissions. The determining
factor will be the amount of coal-fired generation added to Nevada in 2018 and beyond. SPR
continues to evaluate future potential available allowances as well as evaluation of additional
technology to meet the 2018 Phase II cap. New mercury reduction technology is still in its infancy
and as such the form of technology or associated costs cannot be determined at this time.
Regional Haze Rules
— In June 2005, the EPA finalized amendments to the July 1999 regional
haze rules. 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. The EPA requires states to develop implementation plans
to comply with regional haze rules by December 2007. 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. The State
of Nevada has just begun its BART rule development as the first step toward the December 2007
deadline, and SPR is actively involved in the stakeholder process. At this time, it is not clear
which, if any, SPR facilities will require the installation of BART technology or an approved BART
alternative. Due to the uncertainties of technology requirements and timing, SPR is not able to
estimate the cost impact to its facilities at this time.
25
GENERAL – EMPLOYEES (ALL)
SPR and its subsidiaries had 3,212 employees as of January 30, 2007, of which 1,828 were
employed by NPC and 1,266 were employed by SPPC.
NPC’s current contract with the International Brotherhood of Electrical Workers (IBEW) Local
No. 396, which covers approximately 60% of NPC’s workforce, was renegotiated and ratified in April
2005. The new contract is in effect until February 2008. The three-year contract provided for a
4% general wage increase for bargaining unit employees effective February 2, 2005, with 3.75%
increases in 2006 and 2007. In addition, the agreement includes modifications to holiday
schedules, health care cost sharing, retirement benefits and other operational productivity
improvements.
SPPC’s
proposed amendment to its existing contract with the IBEW Local No. 1245, which represents
approximately 65% of SPPC’s workforce, was ratified by the IBEW on February 28, 2007.
The contract, which is expected to be executed in the near future, will be in effect through
December 31, 2009. The three-year contract will provide for an 8%
general wage increase for most bargaining unit employees effective
March 5
th
, 2007, with 4% increases in 2008 and 2009.
Due to protracted negotiations, bargaining unit employees did not
receive a wage increase in 2006 and the negotiated 8% wage increase
in 2007 reflects this. Some classifications will receive lump sum
payments in lieu of a general wage increase and others will receive
equity raises in addition to their general wage increase. Other
significant negotiated items include modifications to holiday
schedules, health care cost sharing, post retirement benefits, and
other operational productivity improvements.
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 2006, the
Utilities collected $107.8 million in franchise or other fees based on gross revenues. They
collected $9.8 million in UEC based on consumption. They also paid and recorded as expense $1.0
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 transmission and
generating facilities. If we are unable to finance such construction or limit the amount of capital
expenditures associated therewith to forecasted levels, our financial condition and results of
operation could be adversely affected.
Our long term business objectives include plans to construct new generating and transmission
facilities. Such construction will require significant capital expenditures 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 SPR. We cannot be sure that we will be able to obtain financing for such
capital expenditures on favorable terms, or at all. 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. If we cannot obtain favorable
financing arrangements for our planned capital expenditures, limit such capital expenditures to
forecasted amounts and/or recover amounts spent on construction through future filings with PUCN,
our financial condition and results of operation would be adversely affected.
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 will therefore be 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. We cannot assure you that the PUCN will issue such orders or that such orders will
be issued on a timely basis.
If Federal and/or State requirements are imposed on NPC and SPPC mandating further emission
reductions, including limitations on carbon dioxide (CO2) emissions, such requirements could make
some electric generating units uneconomical to construct, 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. Environmental advocacy groups and regulatory agencies in the United States have also been
focusing considerable attention on CO2 emissions from power generation facilities and their
potential role in climate change. Although several bills have been introduced in Congress that
would compel CO2 emission reductions, none have advanced through the legislature. Future changes
in environmental regulations governing emissions reductions could make certain electric generating
units uneconomical to construct, maintain or operate. In addition, any legal obligation that would
require the Utilities to substantially reduce its 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.
26
The Utilities are subject to numerous environmental laws and regulations that may increase our cost
of operations, impact or limit our business plans, or expose us to environmental liabilities.
The Utilities are subject to extensive federal, state and local statutes, rules 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, mercury
emissions or greenhouse-gas emissions), water quality and other toxic pollutants may be revised or
new climate change regulations may be adopted or become applicable to us. Revised or additional
regulations, which result in increased compliance costs, increased construction costs 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 and/or if
such regulations make currently contemplated construction projects technologically obsolete or
economically non-viable.
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 halted or subjected to additional costs.
The Utilities may not be able to mitigate fuel and wholesale electricity pricing risks which could
result in unanticipated liabilities and cash flow requirements or increased volatility in our
earnings.
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;
|
|
|
|
|
•
|
|
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 some of
the 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 hold or 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.
27
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.
As of February 23, 2007, NPC had approximately $476.3 million available under its $600 million
revolving credit facility and SPPC has approximately $331.1 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.
If NPC and/or SPPC 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.
The rates that the Utilities charge their customers and certain aspects of their operations
are subject to the regulation of the PUCN, which significantly influences the Utilities’ operating
environment and affects their ability to recover costs from their customers. Under Nevada law,
purchased power, natural gas and fuel costs in excess of those included in base rates are deferred
as an asset on their balance sheets and are not shown as an expense until recovered from their
retail customers. The Utilities are required to file deferred energy applications with the PUCN at
least once every twelve months so that the PUCN may verify the prudence of the energy costs and
allow them to clear their deferred energy accounts. 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.
In January 2007, NPC filed its annual mandatory deferred energy rate case with the PUCN along
with a request to recover costs associated with terminated power contracts. In its deferred
filing, NPC seeks to reduce its base tariff energy rate due to expected lower fuel costs and asks
for recovery of approximately $75 million in past fuel and purchased power costs, both rate changes
to be effective June 1, 2007. The second filing requests recovery of costs associated with the
settlement of claims for power contracts executed during the western energy crisis. NPC is seeking
approximately $21 million per year for a period of four years, to recover costs relating to the
settlement of these claims. While the PUCN has up to 210 days to decide a fuel and purchased power
case, NPC has requested that the rates become effective June 1, 2007.
In December 2006, SPPC filed its annual mandatory deferred energy filing with the PUCN along
with a request to recover costs associated with terminated power contracts. SPPC’s total deferred
energy filing asks for recovery of approximately $18.7 million in past fuel and purchased power
costs. In addition, the required deferred filing includes the setting of a new forward-looking rate
to match the current estimate of costs of fuel and purchased power as well as the expiration of
some rates previously approved by the PUCN. In its terminated power contract filing, SPPC is also
seeking approximately $5 million per year for a period of four years, to recover costs relating to
the settlement of the claims associated with the terminated power contracts.
As of December 31, 2006, NPC’s and SPPC’s unapproved deferred energy costs were $154.1 million
and $28 million, respectively.
Material disallowances of deferred energy costs, gas costs or inadequate base tariff energy
rates would have a significant adverse effect on the Utilities’ financial condition and future
results of operations, could cause downgrades of SPR’s and the Utilities’ securities by the rating
agencies and could make it more difficult to finance operations and construction projects and buy
fuel, natural gas and purchased power from third parties.
If NPC and/or SPPC do not receive favorable rulings in their future general rate cases, 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 changes pursuant to regulatory proceedings
known as general rate cases, which the Utilities file with the PUCN approximately every two years.
In the Utilities’ general rate cases, the PUCN establishes, among other things, their recoverable
rate base, their return on common equity, overall rate of return, depreciation rates and their cost
of capital.
In November 2006, NPC filed its 2006 general rate case with the PUCN. The filing, if approved,
would provide for a $156.4 million increase in its electric rates, for an overall increase of 7.4%.
A decision on NPC’s general rate case is expected in the Spring of 2007.
We cannot predict what the PUCN will direct in their orders on the Utilities’ pending or
future general rate cases. Inadequate base energy rates would have a significant adverse effect on
the Utilities’ financial condition and future results of operations and could cause additional
downgrades of their securities by the rating agencies and make it significantly more difficult to
finance operations and construction projects and to buy fuel, natural gas and purchased power from
third parties.
28
Past regulatory decisions significantly adversely affected our liquidity. Adverse regulatory
decisions could cause downgrades of our credit ratings which, in turn, could limit our access to
the capital markets and make it difficult for the Utilities to obtain power necessary for their
operations.
In March 2002, the PUCN issued a decision in NPC’s deferred energy rate case disallowing $434
million of its request to recover deferred purchased power and fuel costs through rate increases to
its customers. Following this decision by the PUCN, both Standard & Poor’s Ratings Services (“S&P”)
and Moody’s Investors Service, Inc. (“Moody’s”) lowered our unsecured debt ratings to below
investment grade. As a result of these downgrades, our ability to access the capital markets to
raise funds to service our debt obligations and refinance our maturing debt became limited. Since
that time, SPR and the Utilities have completed a series of financings that have extended the debt
maturities, reduced interest costs, improved their capital structure, increased liquidity and
enhanced the credit of SPR and the Utilities. As a result, Moody’s improved the credit ratings of
SPR and the Utilities, and S&P changed our credit outlook to “positive” from “negative.” Fitch
Ratings Ltd. (“Fitch”) and Dominion Bond Rating Service (“DBRS”) commenced credit coverage,
assigning ratings for the two Utilities’ senior secured debt at the minimum level for investment
grade. Currently, Moody’s, S&P, and DBRS have our credit ratings on “stable” outlook and Fitch has
our credit rating on “positive” outlook. SPR and the Utilities will continue to look for
opportunities to improve their financial strength and improve their credit quality. However, any
future downgrades would increase our cost of capital and limit our access to the capital markets.
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 SPR is precluded from receiving dividends from the Utilities, its financial condition and
ability to meet its debt service obligations will be materially adversely affected.
SPR is a holding company with no significant operations of its own. Its cash flows are
substantially derived from dividends paid to it by the Utilities, which are typically utilized to
service SPR’s debt, with the balance, if any, reinvested in SPR’s subsidiaries as contributions to
capital. In the future, subject to various factors to be considered by SPR’s Board of Directors, a
portion of SPR’s cash flow may be used to resume dividend payments on its common stock, in addition
to paying debt service and making capital contributions to SPR’s subsidiaries.
The Utilities are subject to restrictions on their ability to pay dividends to SPR under the
terms of certain of their respective financing agreements and a PUCN order. In addition, certain
provisions of the Federal Power Act could, depending on the interpretation thereof, limit or
prohibit the payment of dividends to SPR.
Assuming that the Utilities meet the requirements to pay dividends under the Federal Power Act
and that any dividends paid to SPR are for SPR’s debt service obligations, under their material
dividend restrictions, each of the Utilities may pay dividends to SPR if each such Utility can meet
a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that
can be paid is an amount less than 50% of such Utilities’ consolidated net income plus the amount
of capital contributions made to such Utility by SPR for the period from the date of issuance of
the respective series of debt securities to the end of the most recently ended fiscal quarter. If
they do not meet these conditions, the Utilities can still pay SPR’s reasonable fees and expenses,
provided that each such Utility has a cash flow to fixed charge coverage ratio of at least
1.75:1 over the prior four fiscal quarters. Due to the cumulative calculation of this restriction,
NPC’s Series G Notes and SPPC’s Series H Notes are effectively the most restrictive dividend
limitations. In addition, under the most restrictive of their dividend restrictions, each of the
Utilities has a carve-out that permits them to pay up to $25 million to SPR from the date of
issuance of the applicable debt securities, regardless of whether the other conditions to paying
dividends have been met. Although each Utility currently meets the conditions described above, a
significant loss by either Utility could cause that Utility to be precluded from paying dividends
to SPR until such time as that Utility again meets the coverage test. The dividend restriction in
the PUCN order may be more restrictive than the Utilities’ individual dividend restrictions because
the PUCN dividend restriction currently limits the amount of dividends paid to SPR collectively by
the Utilities to SPR’s actual cash debt service payments, which amount may be less than the
aggregate amount of the Utilities’ individual dividend restrictions. In 2006, SPR received
approximately $53.7 million in dividends from the Utilities to meet its debt service obligations.
SPR’s indebtedness is effectively subordinated to the liabilities of its subsidiaries, particularly
NPC and SPPC. SPR and the Utilities have the ability to issue a significant amount of additional
indebtedness under the terms of their various financing agreements.
Because SPR 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. SPR
conducts substantially all of its operations through its subsidiaries, and thus SPR’s ability to
meet its obligations under its indebtedness 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 SPR. As of January 31, 2007, the Utilities had approximately $3.5
29
billion of debt outstanding. The terms of SPR’s indebtedness restrict the amount of additional
indebtedness that SPR and the Utilities may issue. Based on SPR’s December 31, 2006 financial
statements, assuming an interest rate of 7%, SPR’s indebtedness restrictions would allow SPR and
the Utilities to issue up to approximately $2.1 billion of additional indebtedness in the
aggregate, unless the indebtedness being issued is specifically permitted under the terms of SPR’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.
Whether SPR can procure sufficient renewable energy sources in each compliance year to comply with
the Portfolio Standard for Renewable Energy.
Currently, the State of Nevada requires compliance with its Portfolio Standard for Renewable
Energy, which mandates that a share of the energy delivered to Nevada retail customers come from
renewable energy resources. This energy is to be provided via direct generation, saved from
portfolio energy systems or realized from implementation of efficiency measures. The Utilities
continue to take affirmative actions to fulfill the Portfolio Standard requirements on their
system. However, the Utilities’ success in meeting the standard remains dependent on creation of
new renewable energy projects, both owned or via output which is purchased from third parties, as
well as maintenance of an ongoing positive climate for renewable energy development across Nevada.
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, war and the threat of terrorism or epidemics may harm our future
growth and operating results.
The growth of our business depends in part on continued customer growth and tourism demand in
the Las Vegas portion of our service area. 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 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 war, terrorism or epidemics may affect our ability to raise
capital.
A continued military presence in Iraq or any other military operations may affect our
operations in unpredictable ways, such as increased security measures and disruptions of fuel
supplies and markets, particularly oil. Uncertainty surrounding retaliatory military strikes or a
sustained military campaign may affect our business in unpredictable ways, including disruptions of
fuel supplies and markets, and the possibility that our infrastructure facilities (which includes
our pipelines, production facilities, and transmission and distribution facilities) could be direct
targets or indirect casualties of an act of terror. War and prolonged military operations may have
an adverse effect on the economy in general, which could adversely affect our business, operations
and financial condition.
ITEM 1B. UNRESOLVED STAFF COMMENTS
SPR, NPC and SPPC have received no written comments regarding their periodic or current
reports from the SEC staff that were issued 180 days or more preceding the end of their 2006 fiscal
year and that remain unresolved
.
ITEM 2. PROPERTIES
Substantially all of NPC’s property in Nevada is subject to the lien of the General and
Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and The Bank of New York, as
trustee, as amended and supplemented.
Substantially all of SPPC’s property in California and Nevada is subject to the lien of the
General and Refunding Mortgage Indenture dated as of May 1, 2001, between SPPC and The Bank of New
York, as trustee, as amended and supplemented.
30
The following is a list of NPC’s share of electric generation plants including the type and
fuel used to generate, the anticipated 2007 net capacity (MW), and the years that the units were
installed.
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Number of
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Winter MW
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Summer MW
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Commercial Operation
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Plant Name
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Type
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Fuel
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Units
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Capacity
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Capacity
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Year
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Clark (1)
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Combined Cycle
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Gas/Oil
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6
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506
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430
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1979, 1979, 1980, 1982, 1993, 1994
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Gas
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Gas/Oil
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1
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63
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54
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1973
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Sunrise
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Steam
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Gas
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1
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82
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80
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1964
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Gas
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Gas/Oil
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1
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81
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70
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1974
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Harry Allen
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Gas
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Gas/Oil
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2
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168
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144
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1995, 2006
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Chuck Lenzie (2)
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Combined Cycle
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Gas
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6
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1,220
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1,102
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2006
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Silverhawk (3)
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Combined Cycle
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Gas
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3
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449
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395
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2004
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Mohave (4)(5)
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Steam
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Coal
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0
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0
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0
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1971, 1971
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Navajo (6)
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Steam
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Coal
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3
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255
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255
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1974, 1975, 1976
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Reid Gardner (7)
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Steam
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Coal
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4
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324
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324
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1965, 1968, 1976, 1983
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|
|
|
|
|
|
|
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Total
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|
|
|
|
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27
|
|
|
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3,148
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2,854
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(1)
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The two combined cycles at Clark 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.
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(2)
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The two combined cycles at Lenzie each consist of two gas turbines, two HRSGs and one steam turbine.
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(3)
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The acquisition of a 75% ownership interest in the 599 MW Silverhawk power station from Pinnacle
West was consummated in 2006. Southern Nevada Water Authority 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.
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(4)
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Per a 1999 Consent Decree, Mohave ceased operation on December 31, 2005. The PUCN approved
establishing regulatory accounts related to the shutdown. See Note 5, Jointly Owned Facilities and
Note 13, Commitments and Contingencies, Regulatory Contingencies, of the Notes to Financial
Statements for further discussion.
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(5)
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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 Station.
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(6)
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NPC has an 11.3% interest in the Navajo Generating Station. The total capacity of the Station is
2,250 MW. Salt River Project 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).
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(7)
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Reid Gardner Unit No. 4 is co-owned by the California Department of Water Resources (CDWR) (67.8%)
and NPC (32.2%); NPC is the operating agent. NPC is entitled to 25 MW of base load capacity and 235
MW of peaking capacity from that Unit, subject to the following limitations: 1,500 hours/year, 300
hours/month, and 8 hours/day. There was a 15 MW upgrade to the Unit in 1990, which is now under
CDWR’s control; the total summer net capacity of the Unit, subject to heat input limitation, is 257
MW. Reid Gardner Units 1, 2, and 3, subject to heat input limitations, are 100 MW each; the total
net capacity of the Station is 557 MW.
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31
The following is a list of SPPC’s share of electric generation plants including the type
and fuel used to generate, the anticipated 2007 net capacity (MW), and the years that the units
became operational.
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|
|
|
|
|
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Number of
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|
Winter MW
|
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Summer MW
|
|
Commercial Operation
|
|
Plant Name
|
|
Type
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Fuel
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Units
|
|
Capacity
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Capacity
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Year
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Ft. Churchill
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Steam
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Gas/Oil
|
|
|
2
|
|
|
|
226
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|
|
|
226
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|
|
1968, 1971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Tracy
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Steam
|
|
Gas/Oil
|
|
|
3
|
|
|
|
244
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|
|
|
244
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|
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1963, 1965, 1974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Tracy 4&5 (1)
|
|
Combined Cycle
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|
Gas
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|
|
2
|
|
|
|
108
|
|
|
|
104
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|
|
1996, 1996
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Clark Mtn. CT’s
|
|
Gas
|
|
Gas/Oil
|
|
|
2
|
|
|
|
144
|
|
|
|
132
|
|
|
1994, 1994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valmy (2)
|
|
Steam
|
|
Coal
|
|
|
2
|
|
|
|
261
|
|
|
|
261
|
|
|
1981, 1985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (3)
|
|
Gas, Diesels
|
|
Propane, Oil
|
|
|
13
|
|
|
|
60
|
|
|
|
56
|
|
|
1960-1970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
24
|
|
|
|
1,043
|
|
|
|
1,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
(1)
|
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Tracy 4&5 were part of the Pinõn Pine Integrated Coal Gasification Combined Cycle power plant located at Tracy Station. This
project was part of the Department of Energy’s Clean Coal Demonstration Program. Although the coal gasification portion of the
facility has never proven operational, the combined cycle unit has been operating on natural gas since 1996. The combined cycle
consists of one combustion turbine, one HRSG, and one steam turbine. In 2003, SPPC installed duct burners, which added 15 MW of
capacity.
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(2)
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Valmy is co-owned by Idaho Power Company (50%) and SPPC (50%); SPPC is the operator. The Plant has a total net capacity of 522 MW.
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|
|
|
(3)
|
|
There are 3 combustion turbines and 10 diesel units included in the “Other” category.
|
ITEM 3. LEGAL PROCEEDINGS
Sierra Pacific Resources and Nevada Power Company
Merrill Lynch/Allegheny Lawsuit
In May 2003, SPR and NPC filed suit against Merrill Lynch & Co., Inc. and Merrill Lynch
Capital Services, Inc. (collectively, Merrill Lynch) and Allegheny Energy, Inc. and Allegheny
Energy Supply Co., LLC (collectively, Allegheny) in the United States District Court, District of
Nevada, for compensatory and punitive damages of $850 million for causing the Public Utilities
Commission of Nevada to disallow the approximate $180 million rate adjustment for NPC in its 2001
deferred energy case (as discussed in Note 13, Commitments and Contingencies of the Notes to
Financial Statements). The PUCN held that NPC acted imprudently when it refused to enter into an
electricity supply contract with Merrill Lynch and subsequently paid too much for electricity from
another source. SPR and NPC allege that Merrill Lynch and Allegheny’s fraudulent testimony and
wrongful conduct caused the PUCN disallowance. Merrill Lynch filed motions to dismiss in May 2003
and June 2003. Thereafter, the case was stayed pending resolution of NPC’s appeal of the 2001
deferred energy case pending before the Nevada Supreme Court, which was decided in August 2006 and
discussed further in Note 13, Commitments and Contingencies of the Notes to Financial Statements.
The Nevada Supreme Court has since rendered its decision in the appeal
.
The Nevada District Court
has yet to rule on the motions to dismiss. In October 2006, the District Court approved a
stipulation continuing a stay of the proceeding pending final resolution of the PUCN remand
proceedings in the 2001 deferred energy case.
Lawsuit Against Natural Gas Providers
In April 2003, SPR and NPC filed a complaint in the U.S. District Court for the
District of Nevada against several natural gas providers and traders. In July 2003, SPR and NPC
filed a First Amended Complaint. A Second Amended Complaint was filed in June 2004, which named
three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El
Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El
Paso Merchant Energy-Gas Company; (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra
Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric. The
defendants filed motions to dismiss, which were granted by the District Court. SPR and NPC
appealed the decision to the Ninth Circuit Court of Appeals. Briefing has been completed. Oral
argument was heard on February 13, 2007. Management cannot predict the
timing or outcome of a decision on this matter.
32
Nevada
Power Company and Sierra Pacific Power Company
Western United States Energy Crisis Proceedings before the FERC
FERC 206 complaints
In December 2001, the Utilities filed ten complaints with the FERC against various power
suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of
forward wholesale power purchase contracts entered into prior to the FERC mandated price caps
imposed in June 2001 in reaction to the Western United States energy crisis. The Utilities
contested the amounts paid for power actually delivered as well as termination claims for
undelivered power against terminating suppliers.
On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the
Utilities had failed to satisfy their burden of proof under the strict public interest standard.
On July 28, 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June
26, 2003 decision. The Utilities appealed this decision to the Ninth Circuit. Oral argument was
held on December 8, 2004. On December 19, 2006, a three judge panel of the Ninth Circuit
overturned the FERC decision and remanded the case back to the FERC for application of the factors
that the Ninth Circuit outlines in its decision. The Company expects one or more of the losing
parties
to file a petition for certiorari seeking review by the U.S. Supreme Court. The parties must file
such a petition within 90 days.
The Utilities have negotiated settlements with Duke Energy Trading and Marketing, Reliant
Energy Services, Inc., Morgan Stanley Capital Group, El Paso Merchant Energy (EPME), now known as
El Paso Marketing L.P.; and Enron, but have been unable to reach agreement in bilateral settlement
discussions with other respondents. In accordance with the Enron Settlement Agreement, the
Utilities withdrew from further participation in the FERC 206 Complaints (including any associated
appeals) as against Enron.
Sierra Pacific Power Company
Piñon Pine
In its 2003 General Rate Case, SPPC sought recovery of its unreimbursed costs associated with
the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project represented
experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology
initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of
construction costs of the Project. SPPC’s participation in the Project had received PUCN approval
as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the
plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal
gasification unit never became fully operational. After numerous attempts to re-engineer the coal
gasifier, the technology was determined to be unworkable. In its order in May 2004, the PUCN
disallowed $43 million of unreimbursed costs associated with the Project. SPPC filed a Petition
for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004
(CV04-01434). In January 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003
General Rate Case and remanded the case back to the PUCN for further review as to whether the costs
were justly and reasonably incurred (Order). In March 2006, the PUCN appealed the Order to the
Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal
to the Supreme Court. In June 2006, the District Court granted PUCN’s motion to stay the Order. In
July 2006, the Supreme Court issued an order questioning the finality of the District Court’s
decision and thus whether it has jurisdiction over the appeal and invited the parties to brief this
matter. The BCP and PUCN responded in early August 2006. The Supreme Court dismissed the appeal in
September 2006. Requests for rehearing were denied in late December 2006, and in January 2007, the
matter was remitted back to the District Court, which, consistent with its January 2006 order,
remanded the matter back to the PUCN for further review. A procedural schedule for this review has
not yet been established.
Other Legal Matters
SPR and it subsidiaries through the course of their normal business operations, are currently
involved in a number of other legal actions, none of which has had or, in the opinion of
management, is expected to have a significant impact on their financial positions or results of
operations.
Environmental Matters
Nevada Power Company
Reid Gardner Station
In August 1999, the Nevada Department of Environmental Protection (NDEP) issued a discharge
permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or
lined with impermeable liners over the following 10 years.
33
This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts.
This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated
remediation requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP
which included proposed dates for corrective action plans and/or suggested additional assessment
plans for each specified area. Any future ponds will be double-lined with inter-liner leak
detection in accordance with the NDEP Authorization to Discharge Permit issued October 2005.
Pond construction and lining costs to satisfy the NDEP order expended to date is approximately
$36 million. Expenditures for 2007 through 2010 are projected to be approximately $10 million.
In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit)
inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting
items and information pertaining to the sources identified in the Title V permit. NPC complied with
the request and any subsequent requests that followed. In September and October 2004, NPC met with
NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with
some elements of its Title V permit, and in December 2004, issued Notices of Alleged Violation
(NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions.
Discussions between NPC and NDEP ensued. In July 2005, NDEP issued new NOAVs. In part, these NOAVs
represent reissuance of the previously issued NOAVs dated December 2004 and address additional
monitoring and reporting issues for the period September 2002 through December 2004. Additional
NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and
reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada
State Environmental Commission and then to judicial review. In July, 2005 NPC received a letter
from the Environmental Protection Agency (EPA) requiring submittal of information relating to
compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC has
responded to the EPA information request. In June, 2006, the EPA issued a Finding and Notice of
Violation (NOV).
NPC has progressed to the final draft stage of dialogue and settlement discussions with NDEP,
EPA and Department of Justice (DOJ) regarding the NOVs and additional environmental controls and
equipment changes, environmental benefit projects, monetary penalties, and/or other measures that
may be required to achieve a settlement of the alleged violations. Management has booked an
estimated minimum liability with respect to these matters. Certain environmental controls and
equipment changes needed to assure compliance with existing or modified regulations were submitted
by NPC to the PUCN in NPC’s 2006 IRP filing. These expenditures were approved by the PUCN in late
2006 and include equipment installation on the various units to control startup opacity and
particulates and reduce operating opacity and oxides of nitrogen.
Clark Station
In July 2000, NPC received a request from the EPA for information to determine the compliance
of certain generation facilities at NPC’s Clark Station with the applicable State Implementation
Plan. In November 2000, NPC and the DAQEM entered into a Corrective Action Order requiring, among
other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March
2001, the EPA issued an additional request for information that could result in remediation beyond
that specified in the November 2000 Corrective Action Order. In October 2003, the EPA issued a
violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the
EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the
alleged violations. In March 2004, the EPA issued another request for information regarding the
turbine blade upgrades, and NPC provided information responsive to this request in April and May
2004. NPC’s position is that a violation did not occur. In May 2006, the EPA, by letter from the
DOJ, notified NPC that it intends to initiate an enforcement action against NPC seeking unspecified
civil penalties, together with injunctive relief, for alleged violations of the Prevention of
Significant Deterioration requirements and Title V operating permit requirements of the Clean Air
Act. NPC has entered into ongoing dialogue and settlement discussions with the EPA and DOJ
regarding the alleged violations. Monetary penalties are not expected to be material and certain
environmental controls and equipment changes needed to assure compliance with existing or modified
regulations were submitted by NPC to the PUCN in January 2007 in NPC’s Second Amendment to the 2006
IRP filing.
NEICO
NEICO, a wholly owned subsidiary of NPC, owns property in Wellington, Utah, which was the site
of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond
of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes
is sufficient to cover reclamation costs. Management is continuing to evaluate various options
including reclamation and sale.
Sierra Pacific Power Company
PCB Treatment, Inc.
In September 1994, Region VII of the EPA notified SPPC that it was being named as a
potentially responsible party (PRP) regarding the past improper handling of Polychlorinated
Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and
the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material
to PCB
34
Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc.;
however, the contaminated material was not disposed of, but remained on-site. A number of the
largest PRP’s formed a steering committee, which completed site investigations and along with the
EPA determined that the Sites should be remediated by removing the buildings to the appropriate
landfills. SPPC is a member of this steering committee. The cleanup has now been completed on
both buildings and is pending inspection and sign off by EPA. The cleanup for the two buildings
came in under budget, as such, SPPC does not expect any further obligations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS
The following are current executive officers of SPR, NPC and SPPC indicated and their ages as
of December 31, 2006. There are no family relationships among them. Officers serve a term which
extends to and expires at the annual meeting of the Board of Directors or until a successor has
been elected and qualified:
Walter M. Higgins, 62, Chairman and Chief Executive Officer, SPR
and Director and Chief Executive Officer of NPC
and SPPC.
Mr. Higgins was elected to his current position on February 15, 2007. Previously, he
was Chairman, President and Chief Executive Officer of SPR and Director and Chief Executive Officer
of NPC and SPPC from August 2000 to February 15, 2007. Mr. Higgins served as Chairman, President
and Chief Executive Officer of AGL Resources, Inc., from February 1998 to August 2000. He is also
a director of AEGIS Insurance Services, the American Gas Association, Edison Electric Institute, and several not-for-profit organizations. He is a trustee of Sierra Nevada College.
Michael W. Yackira, 55, President and Chief Operating Officer, SPR
Mr. Yackira was elected to his current position on February 15, 2007. He was previously
Corporate Executive Vice President and Chief Financial Officer from October 2004 to February 15,
2007. From December 2003 to October 2004 he held the position of Executive Vice President and CFO of SPR,
as well as both NPC and SPPC. Mr. Yackira was previously Executive Vice President, Strategy and Policy,
from January to December 2003. Previously he was the Vice President and CFO of Mars, Inc. from 2001
to 2002. Prior to that, he was with Florida-based FPL Group, Inc. from 1989 to 2000. Mr. Yackira is
a certified public accountant.
Donald L. “Pat” Shalmy, 66, Corporate Senior Vice President, Policy & External Affairs, SPR;
President, NPC
Mr. Shalmy was elected to his present position in November 2004. From July 2002 to October
2004 he held the position of President, NPC. He was previously Senior Vice President, NPC since
May 2002. Formerly he held the position of Director, Government and Community Relations at Kummer,
Kaempfer, Bonner & Renshaw Ltd. Prior to that, Mr. Shalmy was County Manager of Clark County for
12
1
/
2
years and President of the Las Vegas Chamber of Commerce for four years. He is also a
director of the Las Vegas Monorail Company.
Jeffrey L. Ceccarelli, 52, Corporate Senior Vice President, Service Delivery & Operations;
President, SPPC
Mr. Ceccarelli was elected to his present position in October 2004. From June 2000 to October
2004 he held the position of President, SPPC. He previously held the position of Vice President,
Distribution Services, New Business, in July 1999 for SPPC and NPC. A civil engineer, Mr.
Ceccarelli has been with SPPC since 1972.
Paul L. Kaleta, 51, Corporate Senior Vice President, General Counsel and Corporate Secretary, SPR
Mr. Kaleta was elected to his present position in February 2006, and holds the same position
at NPC and SPPC. Previously he was General Counsel for Koch Industries, Inc. and various Koch
subsidiaries from 1998 to 2005. Prior to that, he was Vice President and General Counsel of
Niagara Mohawk Power Company for 8 years and, before that, in the private practice of law as an
associate with Skadden, Arps, Slate, Meagher & Flom and as an associate and then equity member with
Swidler Berlin, Chtd. (now Bingham McCutchen), both in Washington, D.C., for a total of 9 years.
Roberto R. Denis, 57, Corporate Senior Vice President, Energy Supply, SPR, NPC and SPPC
Mr. Denis was elected to his present position in October 2004. From August 2003 to October
2004 he held the position of Vice President, Energy Supply, for NPC and SPPC. From 2001 to 2003,
he held the position of Vice President, Market & Regulatory Affairs, at FPL Energy, LLC. From 1999
to 2001, he held the position of Vice President of Market Services.
35
Stephen R. Wood, 63, Corporate Senior Vice President, Administration, SPR
Mr. Wood was elected to his present position in July 2004 and holds the same position at NPC
and SPPC. He was previously President, Centaur Energy Development LLC, from 2000 to 2004. From
1997 to 2000 he served as President of Louisville Gas and Electric Company and President,
Distribution Services, LG&E Energy Corp. concurrently. He was Executive Vice President and Chief
Administrative Officer, LG&E Energy Corp. from 1994 to 1997. He is also a director of Martin
Engineering, Inc.
William D. Rogers, 46, Corporate Senior Vice President, Chief Financial Officer and Treasurer, SPR
Mr. Rogers was elected to his current position on February 15, 2007. He was previously Vice
President, Finance and Risk and Corporate Treasurer from November 14, 2006 to February 15, 2007.
Prior to that, he was Corporate Treasurer from June 8, 2005 to November 14, 2006. Before joining
SPR, he served as managing director of debt capital markets for Merrill Lynch & Co. in New York
from 2000 to 2005. Prior to that, he served as managing director of debt capital markets with JP
Morgan Chase in New York from 1992 until 2000.
John E. Brown, 56, Controller, SPR
Mr. Brown was elected to his current position in May 2001, and holds the same position at SPPC
and NPC. Previously, he held the position of Director, Corporate and Tax Accounting, and Director,
Internal Audit. Mr. Brown has been with SPR since 1981.
Mary O. Simmons, 51, Vice President, External Affairs, SPPC
Ms. Simmons was elected to her current position in November 2004. From May 2001 to October
2004, she held the position of Vice President, Rates and Regulatory Affairs, for NPC and SPPC.
Previously she held the position of Controller for SPR and SPPC since 1997 and held the same
position with NPC beginning in 1999. Ms. Simmons is a certified public accountant and has been
with SPR since 1985.
36
PART II
|
|
|
|
|
ITEM 5.
|
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (SPR)
|
SPR’s Common Stock is traded on the New York Stock Exchange (symbol SRP). The high and low
sale prices of the Common Stock as reported by NYSE net composite price history for 2006 and 2005
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
High
|
|
Low
|
|
High
|
|
Low
|
|
First Quarter
|
|
$
|
14.60
|
|
|
$
|
12.68
|
|
|
$
|
11.30
|
|
|
$
|
9.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter
|
|
|
14.35
|
|
|
|
12.68
|
|
|
|
13.05
|
|
|
|
10.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Quarter
|
|
|
14.91
|
|
|
|
13.30
|
|
|
|
15.36
|
|
|
|
12.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
|
17.50
|
|
|
|
14.29
|
|
|
|
15.20
|
|
|
|
12.34
|
|
Number of Security Holders:
|
|
|
|
|
|
|
Title of Class
|
|
|
|
Number of Record Holders
|
|
Common Stock:
|
|
$1.00 Par Value
|
|
As of February 23, 2007
:
17,515
|
The Board last declared a dividend on SPR’s Common Stock on February 6, 2002. Since that
time, the Board has determined not to pay a dividend on SPR’s Common Stock. Dividends are
considered periodically by SPR’s Board of Directors and are subject to factors that ordinarily
affect dividend policy, such as current and prospective earnings, current and prospective business
conditions, regulatory factors, SPR’s financial conditions and other matters within the discretion
of the Board, as well as dividend restrictions set forth in SPR’s 8 5/8% Senior Notes due 2014,
7.803% Senior Notes due 2012 and 6.75% Senior Notes due 2017. The Board will continue to review
the factors described above on a periodic basis to determine if and when it would be prudent to
declare a dividend on SPR’s Common Stock. There is no guarantee that dividends will be paid in the
future, or that, if paid, the dividends will be paid at the same amount or with the same frequency
as in the past. See Note 8, Debt Covenant and Other Restrictions of the Notes to Financial
Statements, for a description of the restrictions on NPC’s and SPPC’s ability to pay dividends to
SPR and on SPR’s ability to pay dividends on its common stock.
For information on the equity compensation plans, see Item 12.
37
ITEM 6. SELECTED FINANCIAL DATA
See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of
Operations, for a discussion of factors that may affect the future financial condition and results
of operations of SPR, NPC and SPPC.
SIERRA PACIFIC RESOURCES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
(dollars in thousands; except per share amounts)
|
|
|
|
|
2006
(1)
|
|
|
2005
(2)
|
|
|
2004
(3)
|
|
|
2003
(4)
|
|
|
2002
(5)
|
|
|
Operating Revenues
|
|
$
|
3,355,950
|
|
|
$
|
3,030,242
|
|
|
$
|
2,824,796
|
|
|
$
|
2,787,543
|
|
|
$
|
2,984,604
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
$
|
488,797
|
|
|
$
|
358,678
|
|
|
$
|
333,858
|
|
|
$
|
260,314
|
|
|
$
|
(28,939
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss)
from Continuing Operations
|
|
$
|
279,792
|
|
|
$
|
86,137
|
|
|
$
|
30,842
|
|
|
$
|
(117,286
|
)
|
|
$
|
(297,733
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) from Continuing Operations
Per Average Common Share — Basic and Diluted
|
|
$
|
1.34
|
|
|
$
|
0.46
|
|
|
$
|
0.17
|
|
|
$
|
(1.01
|
)
|
|
$
|
(2.92
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
8,832,076
|
|
|
$
|
7,870,546
|
|
|
$
|
7,528,467
|
|
|
$
|
7,063,758
|
|
|
$
|
7,110,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
$
|
4,001,542
|
|
|
$
|
3,817,122
|
|
|
$
|
4,081,281
|
|
|
$
|
3,579,674
|
|
|
$
|
3,194,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared Per
Common Share
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Income from continuing operations, for the year ended December 31, 2006, includes
reinstatement of deferred energy of approximately $180 million and a $62.9 million gain on
the sale of Tuscarora Gas Pipeline Company’s partnership interest in Tuscarora Gas
Transmission Company.
|
|
|
|
(2)
|
|
Income from continuing operations, for the year ended December 31, 2005, includes a
charge of $54 million for the inducement of debt conversion and the reversal of $20.9
million in interest charges as a result of settlements with terminated suppliers.
|
|
|
|
(3)
|
|
Income from continuing operations, for the year ended December 31, 2004, includes the
reversal of $39.8 million in interest expense due to the decision on the appeal of the
Enron bankruptcy judgment and the write-off of $47.1 million in disallowed plant costs at
SPPC.
|
|
|
|
(4)
|
|
Loss from continuing operations, for the year ended December 31, 2003, was negatively
affected by an unrealized net loss of $46.1 million on the derivative instrument associated
with the issuance of SPR’s $300 million Convertible Notes, $91 million write-off of
deferred energy costs by NPC and SPPC and approximately $52 million of interest charges
related to the Enron litigation.
|
|
|
|
(5)
|
|
Loss from continuing operations and total assets, for the year ended December 31, 2002,
was severely affected by the write-off of deferred energy costs and related carrying
charges of $523 million as a result of the PUCN decision in NPC’s and SPPC’s deferred
energy cases disallowing $434 million and $53 million, respectively, of deferred purchased
fuel and power costs.
|
NEVADA POWER
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
(dollars in thousands)
|
|
|
|
|
2006
(1)
|
|
|
2005
(2)
|
|
|
2004
(3)
|
|
|
2003
(4)
|
|
|
2002
(5)
|
|
|
Operating Revenues
|
|
$
|
2,124,081
|
|
|
$
|
1,883,267
|
|
|
$
|
1,784,092
|
|
|
$
|
1,756,146
|
|
|
$
|
1,901,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
$
|
351,272
|
|
|
$
|
228,827
|
|
|
$
|
216,490
|
|
|
$
|
183,733
|
|
|
$
|
(104,003
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
224,540
|
|
|
$
|
132,734
|
|
|
$
|
104,312
|
|
|
$
|
19,277
|
|
|
$
|
(235,070
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
5,987,515
|
|
|
$
|
5,173,921
|
|
|
$
|
4,883,540
|
|
|
$
|
4,210,759
|
|
|
$
|
4,166,988
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
$
|
2,380,139
|
|
|
$
|
2,214,063
|
|
|
$
|
2,275,690
|
|
|
$
|
1,899,709
|
|
|
$
|
1,683,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared — Common Stock
|
|
$
|
48,917
|
|
|
$
|
35,258
|
|
|
$
|
45,373
|
|
|
$
|
—
|
|
|
$
|
10,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Income from continuing operations, for the year ended December 31, 2006, includes
reinstatement of deferred energy of approximately $180 million.
|
38
|
|
|
|
|
(2)
|
|
For the year ended 2005, Income from Continuing Operations included the reversal of
$17.7 million in interest charges as a result of settlements with terminated suppliers.
|
|
|
|
(3)
|
|
Net Income for the year ended December 31, 2004 included the reversal of $27.5 million
in interest expense due to the decision on the appeal of the Enron bankruptcy judgment.
|
|
|
|
(4)
|
|
Net Income for the year ended December 31, 2003 included a $46 million write-off of
deferred energy costs and $36 million of interest charges related to the Enron litigation.
|
|
|
|
(5)
|
|
Net Loss and Total Assets for the year ended December 31, 2002 was severely affected by
the write-off of $465 million of deferred purchased fuel and power costs and related
carrying charges.
|
SIERRA PACIFIC POWER
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
(dollars in thousands)
|
|
|
|
|
2006
|
|
|
2005
(1)
|
|
|
2004
(2)
|
|
|
2003
(3)
|
|
|
2002
(4)
|
|
|
Operating Revenues
|
|
$
|
1,230,230
|
|
|
$
|
1,145,697
|
|
|
$
|
1,035,660
|
|
|
$
|
1,029,866
|
|
|
$
|
1,081,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
120,017
|
|
|
$
|
116,304
|
|
|
$
|
111,245
|
|
|
$
|
68,566
|
|
|
$
|
55,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
57,709
|
|
|
$
|
52,074
|
|
|
$
|
18,577
|
|
|
$
|
(23,275
|
)
|
|
$
|
(13,968
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
2,807,837
|
|
|
$
|
2,546,301
|
|
|
$
|
2,524,320
|
|
|
$
|
2,362,469
|
|
|
$
|
2,457,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock
|
|
$
|
—
|
|
|
$
|
50,000
|
|
|
$
|
50,000
|
|
|
$
|
50,000
|
|
|
$
|
50,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
$
|
1,070,858
|
|
|
$
|
941,804
|
|
|
$
|
994,309
|
|
|
$
|
912,800
|
|
|
$
|
914,788
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared — Common Stock
|
|
$
|
24,619
|
|
|
$
|
23,933
|
|
|
$
|
—
|
|
|
$
|
18,530
|
|
|
$
|
44,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared — Preferred Stock
|
|
$
|
975
|
|
|
$
|
3,900
|
|
|
$
|
3,900
|
|
|
$
|
3,900
|
|
|
$
|
3,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Income from Continuing Operations, for the year ended December 31, 2005, includes the
reversal in the fourth quarter of $3.2 million in interest expense related to settlement
with terminated suppliers.
|
|
|
|
(2)
|
|
Net Income from Continuing Operations, for the year ended December 31, 2004, was
affected by the write-off of $47.1 million in disallowed plant costs and the reversal of
interest expense of $12.3 million due to the decision on the appeal of the Enron Bankruptcy
judgment and a reduction to income tax expense of $3.3 million as a result of a
flow-through adjustment for pension funding.
|
|
|
|
(3)
|
|
Loss from Continuing Operations, for the year ended December 31, 2003, was affected by
the write off of $45 million in June 2003 of disallowed deferred energy costs and interest
charges of $16 million related to the Enron litigation.
|
|
|
|
(4)
|
|
Loss from Continuing Operations, for the year ended December 31, 2002, was severely
affected by the write-off of $58 million of deferred purchased fuel and power costs and
related carrying charges.
|
39
|
|
|
|
|
ITEM 7.
|
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
Forward-Looking Statements
The information in this Form 10-K includes forward-looking statements within the meaning of
the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to
anticipated financial performance, management’s plans and objectives for future operations,
business prospects, outcome of regulatory proceedings, market conditions and other matters.
Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective”
and other similar expressions identify those statements that are forward-looking. These statements
are based on management’s beliefs and assumptions and on information currently available to
management. Actual results could differ materially from those contemplated by the forward-looking
statements. In addition to any assumptions and other factors referred to specifically in connection
with such statements, factors that could cause the actual results of Sierra Pacific Resources
(SPR), Nevada Power Company (NPC), or Sierra Pacific Power Company (SPPC) to differ materially from
those contemplated in any forward-looking statement include, among others, the following:
|
|
(1)
|
|
unfavorable or untimely rulings in rate cases filed or to be filed by NPC and
SPPC (collectively referred to as the Utilities) with the Public Utility Commission of
Nevada (PUCN), including the periodic applications to recover costs for fuel and
purchased power that have been recorded by the Utilities in their deferred energy
accounts, and deferred natural gas costs recorded by SPPC for its gas distribution
business;
|
|
|
|
|
(2)
|
|
the ability and terms upon which SPR, NPC and SPPC will be able to access the
capital markets to support their requirements for working capital, including amounts
necessary for construction and acquisition costs and other capital expenditures, as well
as to finance deferred energy costs, particularly in the event of unfavorable rulings by
the PUCN, untimely regulatory approval for such financings, and/or a downgrade of the
current debt ratings of SPR, NPC, or SPPC;
|
|
|
|
|
(3)
|
|
whether the Utilities will be able to continue to obtain fuel and power from
their suppliers on favorable payment terms and favorable prices, particularly in the
event of unanticipated power demands (for example, due to unseasonably hot weather),
sharp increases in the prices for fuel and/or power or a ratings downgrade;
|
|
|
|
|
(4)
|
|
changes in environmental laws or regulations, including the imposition of
significant new limits on emissions from electric generating facilities, such as
requirements to reduce carbon dioxide (CO2) emissions, other greenhouse gases and/or
other pollutants in response to climate change legislation;
|
|
|
|
|
(5)
|
|
wholesale market conditions, including availability of power on the spot market,
which affect the prices the Utilities have to pay for power as well as the prices at
which the Utilities can sell any excess power;
|
|
|
|
|
(6)
|
|
changes in the rate of industrial, commercial, and residential growth in the
service territories of the Utilities;
|
|
|
|
|
(7)
|
|
the effect that any construction risks may have on our
business, such as the risk of delays in permitting, changes in
environmental laws, securing adequate skilled labor, cost and
availability of materials and equipment, equipment failure, work
accidents, fire or explosions, business interruptions, possible cost
overruns, delay of in-service dates, and pollution and environmental
damage;
|
|
|
|
|
(8)
|
|
whether the Utilities can procure sufficient renewable energy sources in each
compliance year to satisfy the Nevada Portfolio Standard;
|
|
|
|
|
(9)
|
|
whether NPC will be successful in obtaining PUCN approval to recover the
outstanding balance of its other regulatory assets and other merger costs recorded in
connection with the 1999 merger between SPR and NPC in a future general rate case;
|
|
|
|
|
(10)
|
|
whether the Utilities will be able to continue to pay SPR dividends under the
terms of their respective financing and credit agreements, their regulatory order from
the PUCN, and limitations imposed by the Federal Power Act;
|
|
|
|
|
(11)
|
|
unseasonable weather and other natural phenomena, which, in addition to affecting
the Utilities’ customers’ demand for power, can have a potentially serious impact on the
Utilities’ ability to procure adequate supplies of fuel or purchased power to serve
their respective customers and on the cost of procuring such supplies;
|
|
|
|
|
(12)
|
|
the effect that any future terrorist attacks, wars, threats of war, or epidemics
may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as
well as on the economy in general;
|
|
|
|
|
(13)
|
|
the final outcome of the proceedings to reverse the PUCN’s 2004 decision on
SPPC’s 2003 General Rate Case, which disallowed the recovery of a portion of SPPC’s
costs, expenses and investment in the Piñon Pine Project;
|
40
|
|
(14)
|
|
the timing of the PUCN’s decision regarding the time period NPC is to recover the
approximate $180 million of deferred energy that were disallowed in 2002 and were
reinstated by the Nevada Supreme Court in July 2006;
|
|
|
|
|
(15)
|
|
the timing and final outcome of the PUCN’s decision regarding the Utilities’
recovery of deferred energy costs associated with claims for terminated supplier
contracts;
|
|
|
|
|
(16)
|
|
employee workforce factors, including changes in collective bargaining unit
agreements, strikes or work stoppages;
|
|
|
|
|
(17)
|
|
changes in tax or accounting matters or other laws and regulations to which SPR
or the Utilities are subject;
|
|
|
|
|
(18)
|
|
the effect of existing or future Nevada, California or federal legislation or
regulations affecting electric industry restructuring, including laws or regulations
which could allow additional customers to choose new electricity suppliers or change the
conditions under which they may do so;
|
|
|
|
|
(19)
|
|
changes in the business or power demands of the Utilities’ major customers,
including those engaged in gold mining or gaming, which may result in changes in the
demand for services of the Utilities, including the effect on the Nevada gaming industry
of the opening of additional Indian gaming establishments in California and other
states;
|
|
|
|
|
(20)
|
|
unusual or unanticipated changes in normal business operations, including unusual
maintenance or repairs;
|
|
|
|
|
(21)
|
|
future economic conditions, including inflation rates and monetary policy; and
|
|
|
|
|
(22)
|
|
financial market conditions, including changes in availability of capital or
interest rate fluctuations.
|
Other factors and assumptions not identified above may also have been involved in deriving
these forward-looking statements, and the failure of those other assumptions to be realized, as
well as other factors, may also cause actual results to differ materially from those projected.
SPR, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual
results, changes in assumptions or changes in other factors affecting forward-looking statements.
41
EXECUTIVE OVERVIEW
Management’s Discussion and Analysis of Financial Condition and Results of Operations explains
the general financial condition and the results of operations of Sierra Pacific Resources (SPR) and
its two primary subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC),
collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to SPR and
the Utilities collectively), and includes the following:
|
|
•
|
|
Critical Accounting Policies and Estimates
|
|
|
•
|
|
For each of SPR, NPC and SPPC:
|
|
|
•
|
|
Results of Operations
|
|
|
|
|
•
|
|
Analysis of Cash Flows
|
|
|
|
|
•
|
|
Liquidity and Capital Resources
|
|
|
|
|
•
|
|
Energy Supply (Utilities)
|
|
|
|
|
•
|
|
Regulatory Proceedings (Utilities)
|
SPR’s Utilities operate three regulated business segments which are NPC electric, SPPC
electric and SPPC natural gas. The Utilities are public utilities engaged in the distribution,
transmission, generation and sale of electricity and, in the case of SPPC, sale of natural gas.
Other segment operations consist mainly of unregulated operations and the holding company
operations. The Utilities are the principal operating subsidiaries of SPR and account for
substantially all of SPR’s assets and revenues. SPR, NPC and SPPC are separate filers for SEC
reporting purposes and as such this discussion has been divided to reflect the individual filers
(SPR, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.
The Utilities are regulated by the PUCN and, for the California service territory of SPPC, the
California Public Utilities Commission (CPUC), with respect to rates, standards of service, setting
of and necessity for generation and certain transmission facilities, accounting, issuance of
securities and other matters with respect to generation, distribution and transmission operations.
Under federal law, wholesale rates charged by the Utilities are subject to certain jurisdictional
regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with
respect to rates, service, interconnection, accounting, and other matters in connection with the
Utilities’ sale of electricity for resale and interstate transmission. The FERC also has
jurisdiction over the natural gas pipeline companies from which the Utilities take service. As a
result of regulation, many of the fundamental business decisions of the Utilities, as well as the
rate of return they are permitted to earn on their utility assets are subject to the approval of
governmental agencies.
The Utilities’ revenues and operating income are subject to fluctuations during the year due
to the impacts of 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 typically
occurs in the summer, with a slightly higher peak demand in the winter.
Overview of Major Factors Affecting Results of Operations
During 2006, SPR’s net income applicable to common stock was $277.5 million compared to $82.2
million in 2005. The change in earnings was primarily due to the following items (after income
taxes):
|
|
•
|
|
the July 2006, Nevada Supreme Court ruling which allows NPC to recover
approximately $180 million ($117 million, after tax) of the previously disallowed
deferred energy costs, for further discussion of the legal proceeding, see Note 13,
Commitments and Contingencies of the Notes to Financial Statements;
|
|
|
|
|
•
|
|
the $40.9 million gain on sale of the partnership interest in Tuscarora Gas
Transmission Company (TGTC) held by Tuscarora Gas Pipeline Company’s (TGPC), a
wholly owned subsidiary of SPR;
|
|
|
|
|
•
|
|
improved operating income (excluding the approximate $180 million reinstatement);
|
|
|
|
|
•
|
|
other income of $21.7 million for the carrying charge on Lenzie;
|
|
|
|
|
•
|
|
early tender fees of $6.9 million for the extinguishment of $85 million of SPR’s
8.625% Senior Notes and $25 million of SPR’s 7.803% Senior Notes; and
|
|
|
|
|
•
|
|
a charge recorded in 2005 for $35.1 million in early debt conversion fees
associated with SPR’s convertible notes.
|
42
During 2005, SPR’s net income applicable to common stock was $82.2 million compared to $28.6
million in 2004. The change in earnings was primarily due to the following items (after income
taxes):
|
|
•
|
|
increases in operating income primarily resulting from general rate cases decided in
2004 as well as continued customer growth;
|
|
|
|
|
•
|
|
increases in Allowance for Other Funds used During Construction and Allowance for
Borrowed Funds used During Construction, for a total of approximately $29.3 million,
primarily due to the construction of the Chuck Lenzie Generating Station;
|
|
|
|
|
•
|
|
lower interest expenses due to refinancing activities;
|
|
|
|
|
•
|
|
reversal of interest for energy suppliers on settled disputes of approximately $13.6 million.
|
Partially offsetting these increases in net income applicable to common stock were the
following items (after income taxes):
|
|
•
|
|
early conversion fees of the Convertible Notes of approximately $35.1 million after
taxes and unamortized debt issuance costs and legal fees associated with the various
financing transactions of approximately $6.3 million after taxes;
|
|
|
|
|
•
|
|
legal fees of approximately $7.4 million.
|
Overview of Key Business Issues
During 2006, SPR continued to focus on a “back to the basics” strategy that emphasized the
Utilities’ core business. SPR’s and the Utilities’ strategies were aimed at owning more generating
facilities, thereby reducing dependence on purchased power, while at the same time diversifying
fuel mix for the Utilities’ growing service area. Looking ahead in 2007, SPR and the Utilities
will continue to concentrate on the “back to the basics” strategy. The Utilities will continue to
be subject to the purchased power and natural gas markets that have been volatile in recent years,
in order to meet their obligations to serve their customers. Furthermore, with significant amounts
of construction costs in the Utilities’ future, SPR and the Utilities will need to raise
substantial amounts of capital to fund expenditures. As a result, reducing the cost of capital by
attaining investment grade ratings for the Utilities’ secured debt has been and continues to be a
significant business focus for 2007.
Summarized below are significant business issues in 2006 and the challenges ahead in 2007. It
is not intended to be an exhaustive discussion, nor to suggest that other issues may not arise
during 2007 or thereafter. Details relating to the discussion below can be found in the Notes to
the Financial Statements and elsewhere within this Management’s Discussion and Analysis of
Financial Condition and Results of Operations.
Generation Strategy
In 2003, NPC and SPPC embarked on a strategy to build or acquire electric power plants in
order to reduce their exposure to the energy markets, in an effort to reduce prices and volatility
for its customers, and to provide an opportunity for increased earnings.
Accomplishments towards this goal in 2006 included:
|
|
•
|
|
The completion of the Lenzie generating station, a nominally rated 1,200 MW
natural gas-fired high efficiency combined cycle power plant acquired from Duke
Energy (“Lenzie”).
|
|
|
|
|
•
|
|
In January 2006, NPC completed the $208 million purchase of a 75 percent
ownership interest in the Silverhawk Generating Facility (“Silverhawk”) from
Pinnacle West Capital Corporation (“Pinnacle West”), Pinnacle West Energy
Corporation, a wholly-owned subsidiary of Pinnacle West, and GenWest, LLC.
Silverhawk is a 560-megawatt, natural gas-fueled high efficiency combined-cycle
electric generating facility located 20 miles northeast of Las Vegas.
|
|
|
|
|
•
|
|
The completion of an 80 MW combustion turbine at NPC’s Harry Allen site.
|
With the completion of Lenzie, and the additional unit at NPC’s Harry Allen site, plus the
acquisition of Silverhawk, NPC more than doubled its owned capacity since the end of 2005. As a
result, NPC is less dependent upon the wholesale power markets for meeting the energy needs of its
customers and produced approximately 54.3% of its energy needs in 2006 from owned generation, up
from about 39% last year.
In addition, the PUCN granted NPC’s request that Lenzie be designated a critical facility and
allowed a 2% enhancement above NPC’s authorized Return on Equity (ROE) to be applied to the rate
base associated with the Lenzie construction costs expended after acquisition. The order allows
for up to an additional 1%, or a total of 3% enhanced ROE, if the two Lenzie generator units were
brought on line on or before dates specified in the order. In January 2006, NPC declared Block 1
of Lenzie commercially operable and in April 2006 declared Block 2 commercially operable, both
ahead of the dates specified by the PUCN to qualify for the additional enhancement.
43
In 2006, SPPC began construction of a 514 MW gas fired high efficiency combined cycle
generator at the Tracy Plant. SPPC anticipates an in-service date of June 2008. The PUCN also
ordered that SPPC be allowed to include construction work in progress balances in the rate base of
any interim general rate cases, prior to the in-service date, and granted a 1.5% enhanced ROE for
the estimated $421 million investment. The unit will provide needed generation within SPPC’s
control area to reliably serve the growing needs of Northern Nevada.
Looking ahead
In November 2006, the PUCN approved NPC’s 2006 Integrated Resource Plan (“IRP”) and SPPC’s
thirteenth amendment to its 2004 IRP. The Utilities’ IRPs focus on conventional generation,
renewable energy, conservation, and transmission projects to meet Nevada’s growing electricity
needs while diversifying the fuel mix of the Utilities’ generation portfolios. Included in the
PUCN’s approval is Phase 1 of the construction of the Ely Energy Center, a major project to be
located near Ely, Nevada consisting of two 750-megawatt coal-fired generation units. In addition,
the PUCN approved the development and construction of a 250-mile 500kV transmission line that will
deliver electricity from the Ely Energy Center as well as link NPC’s and SPPC’s transmission
systems in the southern and northern portions of the state. The PUCN approved spending up to $300
million for development activities associated with the Ely Energy Center; however, they placed a
$155 million spending limit until the appropriate air permits are obtained. The PUCN established
the project as a “critical facility,” thereby allowing it to qualify for incentives that will be
determined in a later filing. Additionally, the PUCN required NPC and SPPC to file amendments to
their IRPs in early 2008 once elements of the plan, including final costs, can be more accurately
estimated. The current estimate for the Ely Energy Center and the 500kV transmission line is
approximately $3.8 billion.
The PUCN also approved for NPC the construction of 600 megawatts of natural gas-fired
combustion turbine peaking units at Clark Station to be installed in 2008 and 2009 at an
approximate cost of $395 million. In the case of SPPC, the PUCN approved upgrades to the
combustion systems to Valmy Units 1 and 2. For more details of NPC’s IRP and SPPC’s thirteenth
amendment see Regulatory Proceedings later.
Nevada law sets forth the renewable energy portfolio standard (“Portfolio Standard”) requiring
providers of electric service to acquire, generate, or save a specific percentage of its energy
from renewable energy resources (Renewables). Renewables include, but are not limited to:
biomass, geothermal, solar and wind projects. In 2006, the Utilities were required to obtain six
percent of their total energy from Renewables. The Portfolio Standard increases by three percent
(3%) every other year until it reaches 20% in year 2015. In addition, the Portfolio Standard allows
energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio
Standard. Moreover, not less than five percent (5%) of the total Portfolio Standard must be met
from solar resources. In 2007 and 2008 the Utilities will be required to obtain nine percent (9%)
of their total energy from Renewables. The Utilities have embarked on a strategy to invest in
renewable energy that, along with third party contracts, will provide the opportunity for the
Utilities to meet the Portfolio Standard as set forth by Nevada law.
Management of Energy Risk
The Utilities buy coal, natural gas, and oil to operate generating plants as well as buy
wholesale power to meet the energy requirements of their customers. The Utilities also have
invested in and maintain extensive transmission systems that allow the Utilities to move energy to
meet customers’ needs. While NPC has greatly reduced its dependence on wholesale power markets to
meet its customers’ demand, both Utilities continue to have a significant need to tap energy
markets due to the fact that the Utilities’ owned generation is insufficient to meet their
customers’ energy needs. This situation exposes the Utilities to energy risk and uncertainty as to
the Utilities’ cash flow requirements for fuel and wholesale power, the expense the Utilities will
incur as a result of their energy procurement efforts, and the rates the Utilities need to recover
those costs. Energy risk also encompasses reliability risk — the prospect that energy supplies
will not be sufficient to fulfill customer requirements.
The Utilities systematically manage and control each of the energy-related risks through three
primary vehicles – organization and governance, energy risk management programs, and energy risk
control practices.
The Utilities, through the purchases and sale of specified financial instruments and physical
products, maintain an energy risk management program that limits energy risk to levels consistent
with an approved energy supply plan. The energy risk management program provides for the
systematic identification, quantification, evaluation, and management of the energy risk inherent
in the Utilities’ operations.
The Utilities follow PUCN-approved energy supply plans that encompass the reliable and
efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased
power and resource optimization. The process includes assessments of projected loads and
resources, assessments of expected market prices, evaluations of relevant supply portfolio options
available to the Utilities, and evaluations of the risk attributable to those supply portfolio
options. Financial instruments for economic hedging in conjunction with energy purchases and sales
are also used to mitigate these risks.
44
Liquidity and Access to Capital Markets
With volatile energy costs and substantial commitments to construction, SPR and the Utilities’
liquidity needs and access to capital markets was and continues to be a significant business issue.
In 2006, management evaluated opportunities to refinance high yield debt at lower interest rates.
In 2006, SPR and the Utilities completed major financing transactions of approximately $1.6
billion that lowered our interest costs, improved liquidity and extended maturities which include:
|
|
•
|
|
issuance of $325 million of NPC’s 6.5% General and Refunding Mortgage Notes, Series O, due 2018
|
|
|
|
|
•
|
|
issuance of $370 million of NPC’s 6.65% General and Refunding Mortgage Notes, Series N, due 2036
|
|
|
|
|
•
|
|
issuance of $210 million of NPC’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016
|
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|
|
|
•
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|
issuance of $92.5 million of various NPC Pollution Control Refunding Revenue Bonds
|
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|
|
|
•
|
|
increases to NPC’s and SPPC’s Revolving Credit facilities to $600 million and $350 million, respectively
|
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|
|
|
•
|
|
issuance of $300 million of SPPC’s 6.0% General and Refunding Mortgage Notes, Series M, due 2016
|
|
|
|
|
•
|
|
issuance of $268 million of SPPC’s Pollution Control and Gas and Water Facilities
Refunding Revenue Bonds, Series 2006, 2006A, 2006B and 2006C
|
|
|
|
|
•
|
|
SPR tendered for and extinguished approximately $85 million of SPR’s 8.625%
Senior Notes and approximately $25 million of SPR’s 7.803% Senior Notes
|
|
|
|
|
•
|
|
redemptions of various NPC debt of approximately $667.8 million
|
|
|
|
|
•
|
|
redemption and payments of various SPPC debt of approximately $487 million
|
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|
|
|
•
|
|
redemption of $50 million of SPPC’s Series A Preferred Stock
|
In August 2006, SPR issued 20 million shares of its $1 par value common stock. Net proceeds
from the issuance were $280.6 million. In August 2006, SPR made a capital contribution to NPC for
approximately $200 million. On December 27, 2006, SPR contributed capital to SPPC of approximately
$75 million. SPR has invested the remaining proceeds in highly liquid short-term investments
pending their use for general corporate purposes. As of December 31, 2006, SPR has 350 million
shares of common stock authorized and approximately 221 million shares of common stock issued and
outstanding.
Looking ahead
Management has been and continues to be focused on returning the Utilities’ senior secured
debt to investment grade credit quality. Significant amounts of capital may be necessary to fund
the construction costs of new power plants and, as a result, management may be required to meet
such financial obligation with a combination of internally generated funds, the use of the
Utilities’ revolving credit facilities, the issuance of long-term debt, and, if necessary, capital
contributions from SPR. If energy costs rise at a rapid rate, and the Utilities do not recover, in
a timely manner, the cost of fuel and purchased power, the Utilities may need to issue more debt to
support their operating costs or may need to delay capital expenditures.
Regulatory
As is the case with most regulated entities, the Utilities are frequently involved in various
regulatory proceedings. The Utilities are required to file for annual rate adjustments to provide
recovery of their fuel and purchased power costs. They are also required to file rate cases every
two years to adjust general rates that include their cost of service and return on investment in
order to more closely align earned returns with those allowed by regulators. In addition, as
necessary, the Utilities can file for a change to their Base Tariff Energy Rates (BTER) to more
closely match actual prices. The Utilities remain committed to maintaining a positive relationship
with their regulators. Details regarding recently approved and pending rate cases are discussed
below in
Regulatory Proceedings
discussed later.
45
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
SPR prepared its consolidated financial statements in accordance with accounting principles
generally accepted in the United States of America. In doing so, certain estimates were made that
were critical in nature to the results of operations. The following discusses those significant
estimates that may have a material impact on the financial results of SPR and the Utilities and are
subject to the greatest amount of subjectivity. Senior management has discussed the development and
selection of these critical accounting policies with the Audit Committee of SPR’s Board of
Directors. The items discussed below represent critical accounting estimates that under different
conditions or using different assumptions could have a material effect on the financial condition,
results of operation, cash flows, liquidity and capital resources of SPR and the Utilities.
Regulatory Accounting
The Utilities’ retail rates are currently subject to the approval of the PUCN and, in the case
of SPPC, they are also subject to the CPUC and are designed to recover the cost of providing
generation, transmission and distribution services. As a result, the Utilities qualify for the
application of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the
Effects of Certain Types of Regulation,” issued by the Financial Accounting Standards Board (FASB).
This statement recognizes that the rate actions of a regulator can provide reasonable assurance of
the existence of an asset and requires the capitalization of incurred costs that would otherwise be
charged to expense where it is probable that future revenue will be provided to recover these
costs. SFAS No. 71 prescribes the method to be used to record the financial transactions of a
regulated entity. The criteria for applying SFAS No. 71 include the following: (i) rates are set by
an independent third party regulator, (ii) approved rates are intended to recover the specific
costs of the regulated products or services, and (iii) rates that are set at levels that will
recover costs can be charged to and collected from customers. Under federal law, wholesale rates
charged by the Utilities are subject to certain jurisdictional regulation, primarily by the FERC.
The FERC has jurisdiction under the Federal Power Act with respect to rates, service,
interconnection, accounting, and other matters in connection with the Utilities’ sale of
electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural
gas pipeline companies from which the Utilities take service.
Regulatory assets represent incurred costs that have been deferred because it is probable they
will be recovered through future rates collected from customers. Regulatory liabilities generally
represent obligations to make refunds to customers for previous collections for costs that are not
likely to be incurred. Management regularly assesses whether the regulatory assets are probable of
future recovery by considering factors such as applicable regulatory environment changes and the
status of any pending or potential deregulation legislation. Although current rates do not include
the recovery of all existing regulatory assets as discussed further below and in Note 1, Summary of
Significant Accounting Policies of the Notes to Financial Statements, management believes the
existing regulatory assets are probable of recovery. Management’s judgment reflects the current
political and regulatory climate in the state, and is subject to change in the future. If future
recovery of costs ceases to be probable, the write-off of regulatory assets would be required to be
recognized as a charge and expensed in current period earnings.
Regulatory Accounting affects other Critical Accounting Policies, including Deferred Energy
Accounting, Accounting for Pensions, and Accounting for Derivatives and Hedging Activities, all of
which are discussed immediately below.
Deferred Energy Accounting
Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed
fuel and purchased power costs recoverable through current rates, the excess is not recorded as a
current expense on the statement of operations but rather is deferred and recorded as an asset on
the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs
recoverable through current rates exceed actual fuel and purchased power costs. These excess
amounts are reflected in adjustments to rates and recorded as revenue or expense in future time
periods, subject to PUCN approval. Pursuant to AB 369, Nevada law provides that the PUCN may not
allow the recovery of any costs for purchased fuel or purchased power “that were the result of any
practice or transaction that was undertaken, managed or performed imprudently by the electric
utility.” In reference to deferred energy accounting, Nevada law specifies that fuel and purchased
power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase
energy. Both Utilities are entitled under statute to utilize deferred energy accounting for their
electric operations and both Utilities accumulate amounts in their deferral of energy costs
accounts. The Utilities also record, and are eligible under the statute to recover, a carrying
charge on such deferred balances, recognized as interest income in the current period.
The Utilities are exposed to commodity price risk primarily related to changes in the market
price of electricity as well as changes in fuel costs incurred to generate electricity. See Item
7A, Quantitative and Qualitative Disclosures About Market Risk, for a discussion of the Utilities’
purchased power procurement strategies, and commodity price risk and commodity risk management
program. Currently, commodity price increases are recoverable through the deferred energy
accounting mechanism, with no anticipated effect on earnings. However, the Utilities are subject to
regulatory risk related to commodity price changes due to the fact that the PUCN may disallow
recovery for any of these costs that it considers imprudently incurred.
See Note 3, Regulatory Actions of the Notes to Financial Statements, for additional discussion
of the regulatory process to recover these deferred costs and description of the PUCN’s
disallowance of significant amounts in NPC’s 2001 deferred energy cases.
46
Accounting for Derivatives and Hedging Activities
SPR, NPC, and SPPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” as amended. SFAS No. 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those instruments at fair
value. The accounting for derivatives depends on the intended use of the derivatives and the
resulting designation.
Fuel and Purchased Power Contracts
In order to manage loads, resources, and energy price risk, the Utilities enter into forward
contracts to purchase or sell a specified amount of energy at a specified time, or during a
specified period, in the future. In addition to forward fuel and power contracts, the Utilities
also use over-the-counter options with financial institutions and other energy companies to manage
price risk. All of these instruments are considered to be derivatives under SFAS No. 133 and are
marked to market in the statement of financial position unless the contract qualifies for the
normal purchases or sales exemption per the criteria in SFAS No. 133. The risk management assets
and liabilities recorded in the balance sheets of the Utilities and SPR are primarily comprised of
the fair value of options and these forward fuel and power contracts and other energy related
derivative instruments.
In conjunction with the issuance of SFAS No. 133, the Public Utilities Commission of Nevada
(PUCN) and in the case of SPPC, the California Public Utility Commission (CPUC) issued accounting
orders authorizing the Utilities to offset any derivative assets or liabilities with a regulatory
asset or liability. This accounting treatment is intended to defer the recognition of mark to
market gains and losses on energy commodity transactions until the period of settlement. The order
provides for the Utilities to not recognize the unrealized gain or loss on utility derivative
commodity instruments in the statement of operations and comprehensive income. Fuel and purchased
power costs are subject to this accounting order and apply deferred energy accounting. Upon
settlement of a derivative instrument, actual fuel and purchased power costs are recognized in the
period of settlement if currently recoverable or deferred if they are recoverable or payable
through future rates.
The fair values of the forward contracts are determined based on quotes obtained from
independent brokers and exchanges. The fair values of options are determined using a pricing model
that incorporates assumptions such as the underlying commodity’s forward price curve, time to
expiration, strike price, interest rates, and volatility. The use of different assumptions and
variables in the model could have a significant impact on the valuation of the instruments. The
fair value of the Utilities derivative commodity instruments, which are recorded on the
Consolidated Balance Sheet, are sensitive to market price fluctuations that can occur on a daily
basis.
Accounting for Income Taxes
As of December 31, 2006, net operating losses (NOLs) were $227.1 million. The NOLs may be
utilized in future periods to reduce taxes payable to the extent that SPR and the Utilities
recognize taxable income.
The following table summarizes the NOL and tax credit carry-forwards and associated
carry-forward periods, and a valuation allowance for amounts which SPR has determined that
realization is uncertain (dollars in thousands):
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
Expiration
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|
|
|
Deferred Tax Asset
|
|
Valuation Allowance
|
|
Net Deferred Tax Asset
|
|
Period
|
|
|
|
|
|
Federal NOL
|
|
$
|
213,024
|
|
|
$
|
—
|
|
|
$
|
213,024
|
|
|
|
2020-2023
|
|
|
State NOL
|
|
|
1,058
|
|
|
|
—
|
|
|
|
1,058
|
|
|
|
2008-2013
|
|
|
Research and development credit
|
|
|
3,764
|
|
|
|
—
|
|
|
|
3,764
|
|
|
|
2021-2025
|
|
|
Alternative minimum tax credit
|
|
|
8,696
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|
|
|
—
|
|
|
|
8,696
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|
|
indefinite
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|
Arizona state coal credits
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|
|
1,292
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|
|
|
732
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|
|
|
560
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|
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2007-2011
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Total
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|
$
|
227,834
|
|
|
$
|
732
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|
|
$
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227,102
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|
At December 31, 2006, the Utilities had gross federal and state NOL carry-forwards of
$608.6 million and $12.0 million, respectively.
Considering all positive and negative evidence regarding the utilization of the Utilities’
deferred tax assets, it has been determined that the Utilities are more likely than not to realize
all recorded deferred tax assets, except for the Arizona coal tax credits. As such, these Arizona
coal tax credits represent the only valuation allowance that has been recorded as of December 31,
2006.
Environmental Contingencies
SPR and its subsidiaries are subject to federal, state and local regulations governing air and
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 United States Environmental Protection Agency
47
(EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Department of Air
Quality and Environmental Management (DAQEM) administer regulations involving air and water
quality, solid, and hazardous and toxic waste.
SPR and its subsidiaries are subject to rising costs that result from a steady increase in the
number of federal, state and local laws and regulations designed to protect the environment. These
laws and regulations can result in increased capital, operating, and other costs as a result of
compliance, remediation, containment and monitoring obligations, particularly with laws relating to
power plant emissions. In addition, SPR or its subsidiaries may be a responsible party for
environmental clean up at any site identified by a regulatory body. The management of SPR and its
subsidiaries cannot predict with certainty the amount and timing of all future expenditures related
to environmental matters because of the difficulty of estimating clean up costs and compliance and
the possibility that changes will be made to the current environmental laws and regulations. There
is also uncertainty in quantifying liabilities under environmental laws that impose joint and
several liability on all potentially responsible parties. SPR and its subsidiaries accrue for
environmental costs only when they can conclude that it is probable that they have an obligation
for such costs and can reasonably determine the amount of such costs.
Note 13, Commitments and Contingencies of the Notes to Financial Statements, discusses the
environmental matters of SPR and its subsidiaries that have been identified, and the estimated
financial effect of those matters. To the extent that (1) actual results differ from the estimated
financial effects, (2) there are environmental matters not yet identified for which SPR or its
subsidiaries are determined to be responsible, or (3) the Utilities are unable to recover through
future rates the costs to remediate such environmental matters, there could be a material adverse
effect on the financial condition and future liquidity and results of operations of SPR and its
subsidiaries.
Defined Benefit Plans and Other Postretirement Plans
As
further explained in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to
Financial Statements, SPR maintains a qualified pension plan, a non-qualified supplemental
executive retirement plan (SERP) and restoration plan, as well as an other postretirement benefit (OPEB)
plan that provides health and life insurance for retired employees. All employees are eligible for
these benefits if they terminate with certain age and service requirements from the qualified and
restoration plans, or if they reach retirement age and meet certain service requirements under the
SERP and OPEB plans while still working for SPR or its subsidiaries. These costs are determined in
accordance with the provisions of SFAS No. 87, “Employers’ Accounting for Pensions,” and SFAS No.
106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” and are ultimately
collected in rates billed to customers. Amounts are funded to trusts maintained for the plans. The
amounts funded are then used to meet benefit payments to plan
participants. SPR contributed $17.3
million and $17 million to its pension plan, in 2006 and 2005, respectively, and $8.6 million and
$14.9 million to the other postretirement benefits plan in 2006 and 2005, respectively. At the
present time it is not expected that any additional funding for the pension plan will be required
for plan years 2006 or 2007 to meet the minimum funding levels defined by ERISA. However, SPR and the
Utilities currently expect to contribute in 2007 an amount similar to the 2006 funding. The amounts to
contribute may change subject to market conditions. SPR uses a
September 30 measurement date for its benefit plans.
Pension Plans
SPR’s reported costs of providing non-contributory defined pension benefits (described in Note
11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements) are
dependent upon numerous factors resulting from actual plan experience and assumptions of future
experience.
For example, pension costs are impacted by actual employee demographics (including age and
employment periods), the level of contributions SPR makes to the plan, and earnings on plan assets.
Changes made to the provisions of the plan may also impact current and future pension costs.
Pension costs may also be significantly affected by changes in key actuarial assumptions, including
anticipated rates of return on plan assets, the discount rates and
demographic (mortality, retirement, termination) assumptions used in
determining the projected benefit obligation and pension costs.
In accordance with SFAS No. 87, changes in pension obligations associated with these factors
may not be immediately recognized as pension costs on the income statement, but generally are
recognized in future years over the remaining average service period of plan participants. As such,
significant portions of pension costs recorded in any period may not reflect the actual level of
cash benefits provided to plan participants. SPR adopted SFAS 158 (Note 1 of Notes to the Financial
Statements, Recent Pronouncements) in 2006. This pronouncement requires the immediate recognition
of changes in benefit obligations due to differences between actuarial assumptions and actual
experience in Accumulated Other Comprehensive Income, net of taxes. However, since SPR recovers
SFAS 87 and SFAS 106 costs through rates, these amounts will be recorded as Other Regulatory Assets
under the provisions of SFAS 71, and will be recognized as expense over a period of time. For the
twelve months ended December 31, 2006, 2005, and 2004, SPR
recorded pension expense for all pension plans of
approximately $30.6 million, $23.5 million, and $28.3 million, respectively, in accordance with the
provisions of SFAS No. 87. Actual payments of benefits made to retirees and terminated vested
employees for the twelve months ended September 30, 2006, 2005 and 2004 were $21 million, $20.3
million and $17.5 million respectively.
48
SPR has not made changes to pension plan provisions in 2006, 2005, and 2004 that had
significant impacts on recorded pension expense for these years. As
further described in Note 11,
Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, SPR increased
the discount rate used in determining pension expense from 5.75% in 2006
to 6.00% for the
calendar year 2007. For 2006, SPR moved to a more up-to-date mortality table. SPR also updated termination and
retirement assumptions used to value benefit obligations as of
December 31, 2006 as a result of an experience study.
SPR’s pension plan assets are primarily made up of equity and fixed income investments.
Fluctuations in actual equity market returns as well as changes in general interest rates may
result in increased or decreased pension costs in future periods. Likewise, changes in assumptions
such as current discount rates, mortality assumption and/or expected rates of return on plan assets
could also increase or decrease recorded pension costs.
The following chart reflects the sensitivities associated with a change in certain actuarial
assumptions by the indicated percentage for all pension plans. While the chart below reflects an increase in the
percentage for each assumption, SPR and its actuaries expect that a decrease would impact the
projected benefit obligation (PBO) and the reported annual pension cost (PC) by a similar amount in
the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on
a change in that assumption only.
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Change in
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Impact on
|
|
Impact on
|
|
Actuarial Assumption
|
|
Assumption
|
|
PBO
|
|
PC
|
|
(dollars in millions)
|
|
Incr/(Decr)
|
|
Incr/(Decr)
|
|
Incr/(Decr)
|
|
Discount Rate
|
|
|
1
|
%
|
|
$(82.4)
|
|
$(10.8)
|
|
Rate of Return on Plan Assets
|
|
|
1
|
%
|
|
N/A
|
|
$ (5.3)
|
In selecting an assumed discount rate for fiscal years 2006 and 2005 disclosures, and for
fiscal years 2006 and 2005 pension cost, SPR’s projected benefit payments were matched to the yield
curve derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to
90th percentiles of these bond yields.
In selecting an assumed rate of return on plan assets, SPR considers past performance and
economic forecasts for the types of investments held by the plan. Investment returns on plan
assets in the retirement plan gained approximately $34.4 million
in 2006 and $55.7 million in 2005. These returns, in conjunction with SPR’s
contributions, have improved the funded status compared to prior years.
Other Postretirement Benefits
SPR’s
reported costs of providing other postretirement benefits (described
in Note 11,
Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements) are dependent
upon numerous factors resulting from actual plan experience and assumptions of future experience.
For example, other postretirement benefit costs are impacted by actual employee demographics
(including age and employment periods), the level of contributions made to the plan, earnings on
plan assets, and health care cost trends. Changes made to the provisions of the plan may also
impact current and future other postretirement benefit costs. Other postretirement benefit costs
may also be significantly affected by changes in key actuarial assumptions, including anticipated
rates of return on plan assets, discount rates and demographic
(mortality, retirement, termination) assumptions used in determining the postretirement
benefit obligation and postretirement costs.
For the twelve months ended December 31, 2006, 2005 and 2004, SPR recorded other
postretirement benefit expense of approximately $14.6 million, $14.1 million, and $13.4 million,
respectively, in accordance with the provisions of SFAS No. 106. Actual payments of benefits made
to retirees for the twelve months ended September 30, 2006, 2005
and 2004 were $12.0 million, $8.1
million, and $8.0 million respectively.
SPR has not made changes to other postretirement benefit plan provisions in 2006, 2005, and
2004 that have had any significant impact on recorded benefit plan amounts. As further described in
Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, SPR has
revised the discount rate for its 2006 disclosures to 6.00%, as compared to 2005
disclosures of 5.75%. For determining the expense to be
recorded in 2007, SPR moved to a 6.00% discount rate from 5.75% in
2006. For 2006 expense, SPR also moved to a more up-to-date mortality
table. SPR also updated termination and retirement
assumptions used to value benefit obligations as of December 31, 2006
as a result of an experience study. The medical inflation trend
assumption used to measure obligations was updated to reflect current
expectations and recent experience by large employer health plans. In determining the other postretirement benefit obligation and related cost, these
assumptions can change from period to period, and such changes could result in material changes to
such amounts. SPR is proposing a change to the plan for SPPC’s
bargaining unit 1245 employees, which was ratified on February 28,
2007, with final approval expected in March 2007. The proposed
change would require a re-measurement of plan obligations.
SPR’s other postretirement benefit plan assets are primarily made up of equity and fixed
income investments. Fluctuations in actual equity market returns, as well as, changes in general
interest rates may result in increased or decreased other postretirement benefit costs in future
periods. Likewise, changes in assumptions regarding current discount rates and expected rates of
return on plan assets could also increase or decrease recorded other postretirement benefit costs.
49
The following chart reflects the sensitivities associated with a change in certain actuarial
assumptions by the indicated percentage. While the chart below reflects an increase in the
percentage for each assumption, SPR and its actuaries expect that a decrease would impact the
projected accumulated other postretirement benefit obligation (APBO) and the reported annual other
postretirement benefit cost (PBC) on the income statement by a similar amount in the opposite
direction. Each sensitivity below reflects an evaluation of the change based solely on a change in
that assumption only.
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|
Change in
|
|
Impact on
|
|
Impact on
|
|
Actuarial Assumption
|
|
Assumption
|
|
APBO
|
|
PBC
|
|
(dollars in millions)
|
|
Incr/(Decr)
|
|
Incr/(Decr)
|
|
Incr/(Decr)
|
|
Discount Rate
|
|
1%
|
|
$(21.4)
|
|
$(1.9)
|
|
Health Care Cost Trend Rate
|
|
1%
|
|
$19.6
|
|
$3.4
|
|
Rate of Return on Plan Assets
|
|
1%
|
|
N/A
|
|
$(0.8)
|
In selecting an assumed discount rate for fiscal year 2006 other postretirement benefits
cost and disclosures, SPR’s projected benefit payments were matched to the yield curve derived from
a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th percentiles of
these bond yields.
In selecting an assumed rate of return on plan assets, SPR considers past performance and
economic forecasts for the types of investments held by the plan. Investment returns on plan
assets gained $8 million in 2006 and $0.4 million in 2005.
Unbilled Receivables
Revenues related to the sale of energy are recorded based on meter reads, which occur on a
systematic basis throughout a month, rather than when the service is rendered or energy is
delivered. At the end of each month, the energy delivered to the customers from the date of their
last meter read to the end of the month is estimated and the corresponding unbilled revenues are
calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days
versus unbilled days, amount of energy procured and generated during that month, historical
customer class usage patterns and the Utilities’ current tariffs. Customer accounts receivable as
of December 31, 2006, include unbilled receivables of $92 million and $83 million for NPC and SPPC,
respectively. Customer accounts receivable as of December 31, 2005 include unbilled receivables of
$80 million and $77 million for NPC and SPPC, respectively.
RECENT PRONOUNCEMENTS
See Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements,
for discussion of accounting policies and recent pronouncements.
SIERRA PACIFIC RESOURCES
RESULTS OF OPERATIONS
Sierra Pacific Resources (Holding Company) and Other Subsidiaries
SPR (Holding Company)
The Holding Company’s (stand alone) operating results included approximately $51.4 million,
$74.3 million, and $88.3 million of long-term debt interest costs for the years ended December 31,
2006, 2005 and 2004 respectively. The decrease in interest costs were primarily due to the
conversion of SPR’s $300 million 7.25% Convertible Notes due 2010, the repurchase of the 7.93%
Senior Notes associated with the PIES, and the reduced interest rate of 7.803% on the Senior Notes
associated with the New PIES. See Note 14, Common Stock and Other Paid-in Capital of the Notes to
Financial Statements, for further discussion on SPR debt. The Holding Company’s operating results
for 2005 were negatively affected by early conversion fees of the Convertible Notes of
approximately $35 million after taxes and unamortized debt issuance costs and legal fees associated
with the Convertible Notes of approximately $4.7 million after taxes. See Note 6, Long-Term Debt
of the Notes to Financial Statements, for further discussion of the conversion of the Convertible
Notes. The Holding Company’s operating results for 2004 were negatively affected by an impairment
of goodwill of approximately $11.7 million and higher interest costs. The Holding Company
recognized charges of approximately $23.7 million during 2004 for tender fees, interest costs and
unamortized debt issuance costs associated with the early extinguishment of SPR’s 8.75% Senior
Unsecured Notes due 2005.
50
Tuscarora Gas Pipeline Company (TGPC)
TGPC, a wholly-owned subsidiary of SPR, sold its partnership interest in TGTC in December
2006. The gain from the sale of TGTC was approximately $40.9 million after taxes. TGPC
contributed approximately $3.3 million after taxes in earnings for the year ended 2006 excluding
the gain. TGPC contributed $5.1 million in net income applicable to common stock for the year
ended December 31, 2005 and $5.2 million in net income applicable to common stock for the year
ended December 31, 2004.
Sierra Pacific Communications
SPC, a wholly-owned subsidiary of SPR, incurred a net loss of $263.4 thousand for the year
ended December 31, 2006, a net loss of $103 thousand for the year ended December 31, 2005, and a
net loss of $3.2 million for the year ended December 31, 2004. SPC’s loss in 2004 was primarily
due to the settlement with Sierra Touch America. See Note 17, Discontinued Operations and Disposal
and Impairment of Long-Lived Assets of the Notes to Financial Statements for further discussion.
Other Subsidiaries
Other Subsidiaries of SPR did not contribute materially to the consolidated results of
operations of SPR.
Sierra Pacific Resources (Consolidated)
See Executive Overview, Results of Operations for SPR Consolidated.
ANALYSIS OF CASH FLOWS
SPR’s consolidated net cash flows increased for the year ended December 31, 2006 compared to
the same period in 2005, due to increases in cash from operating and financing activities, offset
by cash used in investing activities. SPR received net proceeds of approximately $281 million from
the issuance of 20 million shares of common stock in 2006. SPR also received approximately $100
million from the sale of TGTC. In December, SPR utilized a portion of
the proceeds of common
stock issuance and cash on hand for a tender offer that resulted in the extinguishment of
approximately $85 million of SPR’s 8.625% Senior Notes and approximately $25 million of the 7.803%
Senior Notes.
At
various times during 2006, NPC borrowed a total of $710 million under its revolving credit
facility and repaid a total of $860 million, including $150 million borrowed in 2005, using the net
proceeds of issuance of $905 million of NPC’s General and Refunding Mortgage Notes, Series M, N and
O and $200 million capital contribution from SPR. The remainder of the proceeds, together with
the draw on the credit facility and cash from operations, was utilized to redeem approximately $563
million of outstanding debt and to pay associated costs and to finance net construction costs of
$627 million. NPC also refinanced $92.5 million of tax exempt Revenue Bonds with newly issued
auction rate Revenue Bonds during 2006.
At various times during 2006, SPPC borrowed approximately $248 million under its revolving
credit facility, all of which was repaid during 2006. SPPC also issued $300 million in 6.0%
General and Refunding Mortgage Notes, Series M, and $268 million in variable interest Pollution
Control Revenue Bonds. A portion of the draw on the credit line was used to retire approximately
$198 million of SPPC’s Medium Term Notes Series A, B and C. The net proceeds of the $300 million
offering were used to pay off the amount borrowed under the revolving credit facility, redeem $20 million of Medium Term Notes, Series C, redeem $50
million of preferred stock and to pay associated costs, premiums and dividends. Proceeds from Pollution Control Revenue Bonds and cash from operations
were used to retire $269 million of SPPC’s existing tax-exempt bonds.
Cash used for investing activities increased significantly when compared to 2005 primarily due
to the acquisition of Silverhawk by NPC and the expansion of the Tracy Generating Station by SPPC.
This increase was offset by the sale of the investment in Tuscarora for approximately $100 million
and a reduction in construction at Lenzie that was placed in service in 2006.
Cash from operations increased during 2006 when compared to 2005 due to increases in deferred
energy and general rates and a decrease in accounts receivable offset partially by the settlement
with Enron. The increase was also offset by a reduction in accounts payable primarily associated
with purchase power suppliers.
SPR’s consolidated net cash flows decreased for the year ended December 31, 2005 compared to
the same period in 2004, as a result of decreases in cash from operating and financing activities
and an increase in cash used by investing activities. Cash flows for operating activities are
lower in 2005 due to energy costs being higher than amounts recovered in rates in 2005. Offsetting
the decrease in cash from operating activities was the $60 million escrow payment for Enron in
2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of the
revolving credit facilities and an increase in general rates in the second quarter of 2004. The
increase in cash used by investing activities was mainly due to construction at NPC for the Chuck
Lenzie project. The decrease in cash from financing activities in 2005, when compared to 2004, was
primarily due to the reduction of debt issued in 2005.
51
LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)
Overall Liquidity
SPR’s consolidated operating cash flows are primarily derived from the operations of NPC and
SPPC. The primary source of operating cash flows for the Utilities is revenues (including the
recovery of previously deferred energy costs and natural gas costs) from sales of electricity and
natural gas. Significant uses of cash flows from operations include the purchase of electricity
and natural gas, other operating expenses and interest.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available Liquidity as of December 31, 2006 (in millions)
|
|
|
|
SPR
|
|
NPC
|
|
SPPC
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
$
|
24.7
|
|
|
$
|
36.6
|
|
|
$
|
53.3
|
|
|
Balance available on
Revolving Credit
Facility
|
|
|
N/A
|
|
|
|
545.0
|
|
|
|
340.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Available Liquidity
|
|
$
|
24.7
|
|
|
$
|
581.6
|
|
|
$
|
393.9
|
|
|
|
|
|
SPR has approximately $42.5 million payable of debt service obligations for 2007,
which it intends to pay through dividends from subsidiaries. (See “Factors Affecting
Liquidity-Dividends from Subsidiaries” below)
SPR and the Utilities anticipate that they will be able to meet operating costs such as fuel
and purchased power costs with internally generated funds, including the recovery of deferred
energy and external borrowings. However, to fund capital requirements, SPR and the Utilities may
meet such financial obligations with a combination of internally generated funds, the use of the
Utilities’ revolving credit facilities, the issuance of long-term debt, and if necessary, capital
contributions from SPR.
On a consolidated basis, SPR’s overall liquidity continued to improve in 2006. The $200
million combined increase in the Utilities’ revolving credit facilities provides additional
liquidity for increased commodity prices. SPR’s debt profile improved as a result of refinancing
approximately $1.1 billion of long-term debt at the two Utilities. These refinancings are expected
to reduce future interest expense.
SPR designs operating and capital budgets to control operating costs and capital expenditures.
In addition to operating expenses, SPR has continuing commitments for capital expenditures for
construction, improvement and maintenance of facilities.
Detailed below are SPR’s Capital Structure, Capital Requirements, recently completed stock and
financing transactions and factors affecting our ability to obtain debt on favorable terms,
including the effect of our holding company structure and limitation on dividends from the
Utilities.
Capital Structure (SPR Consolidated)
SPR’s actual capital structure on a consolidated basis was as follows at December 31 (dollars
in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
Current Maturities of Long-Term Debt
|
|
$
|
8,348
|
|
|
|
0.1
|
%
|
|
$
|
58,909
|
|
|
|
1.0
|
%
|
|
Long-Term Debt
|
|
|
4,001,542
|
|
|
|
60.3
|
%
|
|
|
3,817,122
|
|
|
|
63.8
|
%
|
|
Preferred Stock
|
|
|
—
|
|
|
|
—
|
%
|
|
|
50,000
|
|
|
|
0.8
|
%
|
|
Common Equity
|
|
|
2,622,297
|
|
|
|
39.6
|
%
|
|
|
2,060,154
|
|
|
|
34.4
|
%
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,632,187
|
|
|
|
100
|
%
|
|
$
|
5,986,185
|
|
|
|
100
|
%
|
|
|
|
|
|
|
Capital Requirements
Construction Expenditures
SPR’s annual consolidated cash construction expenditures have increased since 2003 and are
expected to continue to increase due to programs designed to meet electric load growth and
reliability needs. Cash construction expenditures for the years ended 2006, 2005 and 2004 were
approximately $912 million, $590 million, and $557 million, respectively. SPR’s consolidated cash
requirements for construction expenditures for 2007 are projected to be $1.4 billion. SPR’s
consolidated cash requirements for cash construction expenditures for 2007-2011 are projected to be
$7.8 billion. To fund these capital projects SPR and the Utilities may meet such financial
obligations with a combination of internally generated funds, the use of the Utilities’ revolving
credit facilities, the issuance of long-term debt, and if necessary, capital contributions from
SPR. Depending on the progress of the Ely Energy Center the timing and extent of the estimated
capital expenditures necessary may change.
52
Contractual Obligations (SPR Consolidated)
The table below provides SPR’s contractual obligations on a consolidated basis (except as
otherwise indicated), not including estimated construction expenditures described above, or Pension
funding requirements as discussed in Note 11, Retirement Plan and Post-Retirement Benefits of the
Notes to Financial Statements, as of December 31, 2006, that SPR expects to satisfy through a
combination of internally generated cash and, as necessary, through the issuance of short-term and
long-term debt (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment Due by Period
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Thereafter
|
|
|
Total
|
|
|
NPC/SPPC Long-Term Debt
Maturities
|
|
$
|
8,348
|
|
|
$
|
329,468
|
|
|
$
|
102,738
|
|
|
$
|
7,843
|
|
|
$
|
369,734
|
|
|
$
|
2,654,363
|
|
|
$
|
3,472,494
|
|
|
NPC/SPPC Long-Term Debt Interest
Payments
|
|
|
215,941
|
|
|
|
203,602
|
|
|
|
192,614
|
|
|
|
192,188
|
|
|
|
175,159
|
|
|
|
1,663,305
|
|
|
|
2,642,809
|
|
|
SPR Long-Term Debt Maturities
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
549,209
|
|
|
|
549,209
|
|
|
SPR Long-Term Debt Interest
Payments
|
|
|
42,541
|
|
|
|
42,541
|
|
|
|
42,541
|
|
|
|
42,541
|
|
|
|
42,541
|
|
|
|
135,707
|
|
|
|
348,412
|
|
|
Purchased Power
|
|
|
462,402
|
|
|
|
368,810
|
|
|
|
323,215
|
|
|
|
323,882
|
|
|
|
323,541
|
|
|
|
3,925,708
|
|
|
|
5,727,558
|
|
|
Coal and Natural Gas
|
|
|
451,269
|
|
|
|
147,851
|
|
|
|
123,467
|
|
|
|
95,525
|
|
|
|
82,856
|
|
|
|
544,908
|
|
|
|
1,445,876
|
|
|
Long -Term Service Agreements(1)
|
|
|
15,979
|
|
|
|
13,867
|
|
|
|
24,267
|
|
|
|
22,037
|
|
|
|
12,148
|
|
|
|
123,783
|
|
|
|
212,081
|
|
|
Capital Purchase Agreements
|
|
|
13,121
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
13,121
|
|
|
Southern Operations Center Lease
|
|
|
875
|
|
|
|
3,000
|
|
|
|
3,075
|
|
|
|
3,180
|
|
|
|
3,260
|
|
|
|
65,320
|
|
|
|
78,710
|
|
|
Operating Leases
|
|
|
17,160
|
|
|
|
17,443
|
|
|
|
15,184
|
|
|
|
12,748
|
|
|
|
4,219
|
|
|
|
101,046
|
|
|
|
167,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Cash Obligations
|
|
$
|
1,227,636
|
|
|
$
|
1,126,582
|
|
|
$
|
827,101
|
|
|
$
|
699,944
|
|
|
$
|
1,013,458
|
|
|
$
|
9,763,349
|
|
|
$
|
14,658,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Does not include equipment and services contracts related to the new
peaking units at Clark Generating Station, entered into in February 2007.
Pension Plan Matters
SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC.
The annual net benefit cost for the plan is expected to decrease in 2007 by approximately $1.3
million compared to the 2006 cost of $30.6 million. As of September 30, 2006, the measurement date,
the plan was fully funded on a FAS 87 ABO basis (fair value of assets exceeded ABO). During 2006,
SPR contributed a total of $16 million to meet their funding obligations under the plan. At the
present time it is not expected that any additional funding will be required in 2007 to meet the
minimum funding level requirements defined by the Pension Benefit Guaranty Corporation and ERISA.
However, SPR and the Utilities currently expect to contribute an amount similar to the 2006
funding. The amounts to be contributed may change subject to market conditions.
Capital Stock Transaction (SPR-Holding Company)
On May 1, 2006, SPR’s shareholders approved an amendment to SPR’s Restated Articles of
Incorporation to increase the number of authorized shares of SPR common stock by 100 million
shares, for a total amount of 350 million authorized shares.
In August 2006, SPR issued 20 million shares of its $1 par value common stock. Net proceeds
from the issuance were $280.6 million. In August 2006, SPR contributed capital to NPC for
approximately $200 million. NPC used the proceeds to repay indebtedness under its revolving credit
facility. SPR invested the remaining proceeds in highly liquid short-term investments. In
December 2006 these funds, along with net proceeds from the sale of TGTC, and available cash on
hand, were used to fund the tender offer of a portion of SPR debt and to make a capital
contribution to SPPC of approximately $75 million (see Overall Liquidity above). As of December
31, 2006, SPR had approximately 221 million shares of common stock issued and outstanding.
Financing Transactions (SPR-Holding Company)
Tender Offer
In November 2006, SPR commenced tender offers for up to $110 million aggregate principal
amount of its 7.803% Senior Notes due 2012, its 8.625% Senior Notes due 2014, and its 6.75% Senior
Notes due 2017. Each of the offers was conditioned on SPR purchasing no more than an aggregate
principal amount of $110 million of all notes validly tendered. To meet this condition, SPR
terminated the offer for the 6.75% Notes. In December 2006 approximately $25 million of the 7.803%
Senior Notes outstanding, and approximately $85 million of the 8.625% Senior Notes outstanding were
validly tendered and accepted by SPR. The total consideration paid was approximately $120.6
million (which included an early tender premium and accrued interest). As of December
53
31, 2006,
the outstanding balances for the 7.803% Senior Notes and 8.625% Senior Notes were $74.2 million and
$250.0 million, respectively.
Factors Affecting Liquidity
Effect of Holding Company Structure
As of December 31, 2006, SPR (on a stand-alone basis) has outstanding debt and other
obligations including, but not limited to: $74.2 million of its unsecured 7.803% Senior Notes due
2012; $225 million of its unsecured 6.75% Senior Notes due 2017; and $250 million of its unsecured
8.625% Senior Notes due 2014.
Due to the holding company structure, SPR’s right as a common shareholder to receive assets of
any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is
junior to the claims against the assets of such subsidiary by its creditors and preferred
stockholders. Therefore, SPR’s debt obligations are effectively subordinated to all existing and
future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade
creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
As of December 31, 2006, SPR, NPC, SPPC and their subsidiaries had approximately $4.01 billion
of debt and other obligations outstanding, consisting of approximately $2.39 billion of debt at
NPC, approximately $1.07 billion of debt at SPPC and approximately $549 million of debt at the
holding company and other subsidiaries. Although SPR and the Utilities are parties to agreements
that limit the amount of additional indebtedness they may incur, SPR and the Utilities retain the
ability to incur substantial additional indebtedness and other liabilities.
Dividends from Subsidiaries
Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to
SPR by NPC and SPPC on their common stock, all of which is owned by SPR. 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 the PUCN order for Docket 05-10024 and 05-10025, issued in February 2006, a dividend
restriction was instituted for both Utilities. Under this restriction, the combined amount that NPC
and SPPC may pay to SPR each year is limited to the actual cash necessary to service
SPR’s debt for the year. At the time of the order, SPR and the Utilities were only rated by
Standard & Poor’s (“S&P”), Moody’s Investors Service, Inc.
(“Moody’s”) and Fitch Ratings Ltd. (“Fitch”). The PUCN order
states that the dividend restriction will continue until NPC’s and SPPC’s senior
secured debt obtains an investment grade rating from two of the three credit rating agencies, but
did not specify which rating agencies. In February 2007, Dominion Bond Rating Service
(“DBRS”), who had not previously issued ratings on the companies, assigned ratings
for SPR, NPC and SPPC. DBRS and Fitch currently rate NPC and SPPC’s senior secured
debt at the minimum level for investment grade. It is not clear what effect, if any, the DBRS
rating will have on the PUCN dividend restriction. See “Credit Ratings” below for
discussion of current ratings.
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. The specific agreements entered into by the Utilities, restrictions on
dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory
limitations on dividends, are discussed in Note 8, Debt Covenant and Other Restrictions.
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 SPR
could be jeopardized.
As of December 31, 2006, each Utility was able to pay dividends, subject to a cap, under the
most restrictive test in its financing agreements; however, the total amount of dividends that the
Utilities can pay to SPR under their financing agreements does not currently significantly restrict
their ability to pay dividends because the maximum amount of dividends that can be paid under their
financing agreements is greater than the amount that the Utilities can pay under the PUCN dividend
restriction. In 2006, NPC paid $35.8 million and declared an additional $13.5 million in dividends
to SPR and SPPC paid $17.9 million and declared an additional $6.7 million in dividends to SPR. In
January 2007, SPPC paid $6.7 million in dividends to SPR and NPC paid $13.5 million in dividends to
SPR.
54
Credit Ratings
SPR, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations
S&P, Moody’s, Fitch, and DBRS. As of February 23, 2007
,
the ratings are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rating Agency
|
|
|
|
|
|
DBRS
|
|
Fitch
|
|
Moody’s
|
|
S&P
|
|
SPR
|
|
Sr. Unsecured Debt
|
|
BB (low)
|
|
BB-
|
|
B1
|
|
B
|
|
NPC
|
|
Sr.Secured Debt
|
|
BBB (low)*
|
|
BBB-*
|
|
Bal
|
|
BB+
|
|
NPC
|
|
Sr.Unsecured Debt
|
|
Not rated
|
|
BB
|
|
Not rated
|
|
B
|
|
SPPC
|
|
Sr.Secured Debt
|
|
BBB (low)*
|
|
BBB-*
|
|
Bal
|
|
BB+
|
|
|
|
|
|
*
|
|
Ratings are investment grade
|
In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new
ratings to SPR, NPC and SPPC. The ratings for the senior secured debt of NPC and SPPC are BBB
(low), which is the minimum level for investment grade. The rating assigned to SPR’s senior notes
is BB (low), which is non-investment grade. DBRS’s trend for all three companies is Stable.
In 2006, there were other changes to the ratings of the three companies. Fitch upgraded the
ratings of SPR and the Utilities. The ratings for the senior secured debt of NPC and SPPC were
increased to BBB-, the minimum level for investment grade. The senior unsecured debt for NPC was
upgraded from BB- to BB, which is still non-investment grade. Fitch revised the rating outlook
for SPR and the Utilities from Positive to Stable. S&P upgraded the ratings of NPC’s and SPPC’s
senior secured debt from BB to BB+, one level below investment grade. Moody’s re-affirmed its
ratings for NPC’s and SPPC’s senior secured debt at Ba1, one level below investment grade.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings
are subject to revision and withdrawal at any time by the assigning rating organization, and each
rating should be evaluated independently of any other rating.
Energy Supplier Issues
With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell
electricity with counterparties under the Western Systems Power Pool (WSPP) agreement, an industry
standard contract that NPC and SPPC are required to use as members of the WSPP. The WSPP contract
is posted on the WSPP website.
These contracts provide that a material adverse change may give rise to request adequate
financial assurance, which, if not provided within three business days, could cause a default. A
default must be declared within 30 days of the event, giving rise to the default becoming known. A
default will result in a termination payment equal to the present value of the net gains and losses
for the entire remaining term of all contracts between the parties aggregated to a single
liquidated amount due within three business days following the date the notice of termination is
received. The mark-to-market value, which is substantially based on quoted market prices, can be
used to roughly approximate the termination payment and benefit at any point in time. The net
mark-to-market value as of December 31, 2006 for all suppliers continuing to provide power under a
WSPP agreement would approximate a $55.8 million payment by NPC and an approximate $44.5 million
payment by SPPC. These contracts qualify for the normal purchases scope exception of SFAS No. 133,
and as such, are not required to be marked to market on the balance sheet. Refer to Note 9,
Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.
Gas Supplier Issues
With respect to the purchase and sale of natural gas, NPC and SPPC use several types of
standard industry contracts. The natural gas contract terms and conditions are more varied than
the electric contracts. Consequently, some of the contracts contain language similar to that found
in the WSPP agreement and other agreements have unique provisions dealing with material adverse
changes. Because of creditworthiness concerns, most contracts and confirmations for natural gas
purchases have been modified or separate agreements have been made to either shorten the normal
payment due date or require payment in advance of delivery. At the present time, four
counter-parties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service
contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service
or otherwise post cash or a letter of credit to be able to receive service. Service contracts are
subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to
provide collateral to continue receiving service.
55
Financial Covenants
Nevada Power Company and Sierra Pacific Power Company
Each of NPC’s $600 million Second Amended and Restated Revolving Credit Agreement and SPPC’s
$350 million Amended and Restated Revolving Credit Agreement, dated November 2005, and amended in
April 2006, contains two financial maintenance covenants. The first requires that the Utility
maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last
day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that the Utility maintain
a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day
of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0
to 1. As of December 31, 2006, both Utilities were in compliance with these covenants.
Limitations on Indebtedness
Sierra Pacific Resources
The terms of SPR’s $250 million 8.625% Senior Unsecured Notes due March 2014, $74.2 million
7.803% Senior Unsecured Notes due 2012 and $225 million 6.75% Senior Unsecured Notes due 2017
restrict SPR and any of its Restricted Subsidiaries (NPC and SPPC) from incurring any additional
indebtedness unless:
1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges
for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or
2. the debt incurred is specifically permitted under the terms of the respective series of
Senior Notes, which permits the incurrence of certain credit facility or letter of credit
indebtedness, obligations incurred to finance property construction or improvement, indebtedness
incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging
obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters
of credit supporting SPR’s or any Restricted Subsidiary’s obligations to energy suppliers, or
3. the indebtedness is incurred to finance capital expenditures pursuant to NPC’s 2003
Integrated Resource Plan and SPPC’s 2004 Integrated Resource Plan.
If the respective series of Senior Notes are upgraded to investment grade by both Moody’s and
S&P, these restrictions will be suspended and will no longer be in effect so long as the respective
series of Senior Notes remain investment grade. As of December 31, 2006, SPR, NPC and SPPC would
have been able to issue approximately
$
2.1 billion of additional indebtedness on a consolidated
basis, assuming an interest rate of 7%, per the requirement stated in number 1 above.
Nevada Power Company
Certain factors impact NPC’s ability to issue debt:
|
|
1.
|
|
Financing Authority from the PUCN. In February 2006 NPC received PUCN
authorization to enter into financings of $1.78 billion, which amount included $600
million for the revolving credit facility (described above). NPC has issued
approximately $100 million of the new debt authorized under the PUCN Order. NPC’s only
remaining authority under this PUCN Order allows NPC to refinance its existing debt and
to use its $600 million revolving credit facility.
|
|
|
|
|
2.
|
|
Limits on Bondable Property. To the extent that NPC has the ability to issue
debt under the most restrictive covenants in its financing agreements and has financing
authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited
by the amount of bondable property or retired bonds that can be used to issue debt under
its General and Refunding Mortgage Indenture. As of December 31, 2006, NPC had the
capacity to issue $672 million of General and Refunding Mortgage Securities.
|
|
|
|
|
3.
|
|
Financial Covenants in its and SPR’s financing agreements. The terms of
certain SPR debt further prohibit NPC and SPPC from incurring additional indebtedness
unless certain conditions have been met. In addition to the SPR debt, the terms of
certain NPC debt and the revolving credit facility restrict NPC from incurring any
additional indebtedness unless certain covenants are satisfied. See Note 8, Debt
Covenant and Other Restrictions of the Notes to Financial Statements in this report.
|
As of December 31, 2006, the financial covenants under the revolving credit facility,
which are more restrictive than the financial covenants found in other NPC debt, would
allow NPC to issue up to $2.2 billion of additional debt. The covenant limitations of
certain SPR debt place a cap on additional indebtedness, on a consolidated basis,
including SPPC and NPC, of $2.1 billion as of December 31, 2006. However, since NPC
currently has no PUCN authority to issue new debt, NPC is limited to borrowing under its
credit facility. As of February 23, 2007, the balance available under the credit facility
is
$
476.3 million.
56
Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s
debt covenant limitations may allow for higher or lower borrowings than $2.1 billion,
depending on the Utilities’ combined usage of their respective revolving credit facilities
at the time of the covenant calculation.
Sierra Pacific Power Company
Certain factors impact SPPC’s ability to issue debt:
|
|
1.
|
|
Financing Authority from the PUCN. In February 2006, SPPC received PUCN
authorization to enter into financings of $1.36 billion which amount includes $350
million for the revolving credit facility (described above). SPPC has issued $21
million of the new debt authorized in the PUCN Order. SPPC’s remaining authority under
this PUCN Order allows SPPC to use its $350 million revolving credit facility, to issue
$349 million in new debt, and to refinance existing debt as specified in the order.
|
|
|
|
|
2.
|
|
Limits on Bondable Property. To the extent that SPPC has the ability to issue
debt under the most restrictive covenants in its financing agreements and has financing
authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited
by the amount of bondable property or retired bonds that can be used to issue debt under
the General and Refunding Mortgage Indenture. As of December 31, 2006, SPPC has the
capacity to issue $381 million of General and Refunding Mortgage Securities.
|
|
|
|
|
3.
|
|
Financial Covenants in its and SPR’s financing agreements. The terms of certain
SPR debt further prohibit SPPC and NPC from incurring additional indebtedness unless
certain conditions have been met. In addition to the SPR debt, the terms of certain
SPPC debt and the revolving credit facility restrict SPPC from incurring any additional
indebtedness unless certain covenants are satisfied. See Note 8, Debt Covenant and
Other Restrictions of the Notes to Financial Statements in this report.
|
As of December 31, 2006, the financial covenants under the revolving credit facility,
which are more restrictive than the financial covenants found in other SPPC debt, would
allow SPPC to issue up to $797 million of additional debt. The covenant limitations of
certain SPR debt place a cap on additional indebtedness, on a consolidated basis,
including SPPC and NPC, at $2.1 billion as of December 31, 2006. As of February 23, 2007,
the balance available under the credit facility is $331.1 million.
Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s
debt covenant limitations may allow for higher or lower borrowings than $2.1 billion,
depending on the Utilities’ combined usage of their revolving credit facilities at the
time of the covenant calculation.
Cross Default Provisions
None of the Utilities’ financing agreements contains a cross-default provision that would
result in an event of default by that Utility upon an event of default by SPR or the other Utility
under any of their respective financing agreements. Certain of SPR’s financing agreements,
however, do contain cross-default provisions that would result in event of default by SPR upon an
event of default by the Utilities under their respective financing agreements. In addition,
certain financing agreements of each of SPR and the Utilities provide for an event of default if
there is a failure under other financing agreements of that entity to meet payment terms or to
observe other covenants that would result in an acceleration of payments due. Most of these
default provisions (other than ones relating to a failure to pay other indebtedness) provide for a
cure period of 30-60 days from the occurrence of a specified event, during which time SPR or the
Utilities may rectify or correct the situation before it becomes an event of default.
ENERGY SUPPLY (UTILITIES)
The energy supply function at the Utilities encompasses the reliable and efficient operation
of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource
optimization (i.e., physical and economic dispatch).
The Utilities face energy supply challenges for their respective load control areas. There is
the potential for continued price volatility in each Utility’s service territory, particularly
during peak periods. A greater dependence on gas-fired generation in the service territory subjects
power prices to gas price volatilities. Both Utilities face load obligation uncertainty due to the
potential for customer switching. Some counterparties in these areas have significant credit
difficulties, representing credit risk to the Utilities. Finally, each Utility’s own credit
situation can have an impact on its ability to enter into transactions.
In response to these energy supply challenges, the Utilities have adopted an approach to
managing the energy supply function that has three primary elements. The first element is a set of
management guidelines to procuring and optimizing the supply portfolio that is consistent with the
requirements of a load serving entity with a full requirements obligation. The second element is an
energy
57
risk management and risk control approach that ensures clear separation of roles between the
day-to-day management of risks and compliance monitoring and control; and ensures clear distinction
between policy setting (or planning) and execution. Lastly, the Utilities will pursue a process of
ongoing regulatory involvement and acknowledgement of the resource portfolio management plans.
Energy Supply Planning
Within the energy supply planning process, there are three key components covering different
time frames:
|
|
(1)
|
|
the PUCN-approved long-term IRP filed every three years, which has a twenty-year
planning horizon;
|
|
|
|
|
(2)
|
|
the Energy Supply Plan (“ESP”), which is an intermediate term resource procurement
and risk management plan that establishes the supply portfolio strategies within which
intermediate term resource requirements will be met, has a one to three year planning
horizon; and
|
|
|
|
|
(3)
|
|
tactical execution activities with a one-month to twelve-month focus.
|
The ESP operates in conjunction with the PUCN-approved twenty-year IRP. It serves as a guide
for near-term execution and fulfillment of energy needs. When the ESP calls for executing contracts
with a duration of more than three years, the IRP regulations require PUCN approval as part of the
resource planning process.
In developing energy supply plans and executing such plans, management guidelines followed by
the Utilities include:
|
|
•
|
|
Maintaining an energy supply plan that balances the goals of minimizing costs, risks
and price volatility (retail price stability), while maximizing reliability and
predictability of supply.
|
|
|
|
|
•
|
|
Investigating feasible commercial options to execute the ESP.
|
|
|
|
|
•
|
|
Applying quantitative techniques and diligence commensurate with risk to evaluate and execute each transaction.
|
|
|
|
|
•
|
|
Monitoring the portfolio against evolving market conditions and managing the resource optimization options.
|
|
|
|
|
•
|
|
Ensuring transparent and well-documented decisions and execution processes.
|
Energy Risk Management and Control
The Utilities’ efforts to manage energy commodity (electricity, natural gas, coal and oil)
price risk are governed by a Board of Directors’ revised and approved Enterprise Risk Management
and Control Policy. That policy created the Enterprise Risk Oversight Committee (EROC) and made
that committee responsible for the overall policy direction of the Utilities’ risk management and
control efforts. That policy further instructed the EROC to oversee the development of appropriate
risk management and control policies including the Energy Risk Management and Control Policy.
The Utilities’ commodity risk management program establishes a control framework based on
existing commercial practices. The program creates predefined risk thresholds and delineates
management responsibilities and organizational relationships. The program requires that transaction
accounting systems and procedures be maintained for systematically identifying, measuring,
evaluating and responding to the variety of risks inherent in the Utilities’ commercial activities.
The program’s control framework consists of a disclosure and reporting mechanism designed to keep
management fully informed of the operation’s compliance with portfolio and credit limits.
The Utilities, through the purchase and sale of financial instruments and physical products,
maintain an energy risk management program that limits energy risk to levels consistent with energy
supply plans approved by the Chief Executive Officer and the EROC.
Regulatory Issues
The Utilities’ long-term IRPs are filed with the PUCN for approval every three years. Nevada
law provides that resource additions approved by the PUCN in the resource planning process are
deemed prudent for ratemaking purposes. NPC’s IRP was filed in June 2006 and received approval in
November 2006. SPPC’s IRP was filed in July 2004 and approved on November 2004. Between IRP
filings, the Utilities are required to seek PUCN approval for modifications to their resource plans
and for power purchases with terms of three years or greater by filing amendments to prior IRP
filings.
The Utilities also seek regulatory input and acknowledgement of intermediate term energy
supply plans. The Utilities feel this is necessary to ensure that the appropriate levels of risks
are being mitigated at reasonable costs, the appropriate levels of risks are being retained in the
portfolio, and decisions to manage risks with best available information at the point in time when
decisions are made are subject to reasonable mechanisms for recovery in rates.
58
Intermediate Term Energy Supply Plans
The Utilities update their intermediate term ESPs on an annual basis. In June 2006, NPC
filed a new 20 year IRP, which included an ESP for years 2007-2009. In July 2006, SPPC filed the
Thirteenth Amendment to its 2004 IRP which included, among other things, an ESP update for the
remaining year of the planning cycle, 2007. Both plans were approved by the EROC and the CEO prior
to submission to the PUCN. The Energy Supply Plans operate within the framework of the
PUCN-approved twenty-year IRPs.
They serve as a guide for near-term execution and fulfillment of energy needs. When the ESPs
call for the execution of contracts of duration of more than three years, an amendment to the IRP
is prepared and submitted for PUCN approval. The fuel, power procurement and risk management
strategies contained in the ESPs filed in 2006 were found to be reasonable and prudent by the PUCN
in November 2006.
In 2006, NPC added a significant amount of new, efficient, generating capacity to its system
(Lenzie 1 and 2, Silverhawk and Harry Allen 4), essentially doubling the amount of Company-owned
generating resources. For the remainder of their power needs, the PUCN approved ESPs provide for a
competitive acquisition process to secure the required resources. Both Utilities have issued
Requests For Proposals and executed forward contracts for their peak resource needs for the summer
of 2007. The portfolio mix consists of owned generating resources, forward contracts for power and
peaking and seasonal capacity, or synthetic tolling based contracts (i.e., power prices indexed to
gas prices), to meet the following requirements:
|
|
•
|
|
Optimize the tradeoff between overall fuel and purchase power cost and market price and supply risk.
|
|
|
|
|
•
|
|
Pursue in-region capacity to enhance long-term regional reliability.
|
|
|
|
|
•
|
|
Represent the set of transactions/products available in the market.
|
|
|
|
|
•
|
|
Reduce credit risk—in a market with some counter-parties in weak financial conditions.
|
|
|
|
|
•
|
|
Procure to match a difficult load profile, to the extent possible.
|
|
|
|
|
•
|
|
Hedge the gas price risk exposure in the fuel portfolio through the purchase of a set of risk management options.
|
|
|
|
|
•
|
|
Manage energy price risk through ongoing intermediate and short-term
optimization activities (e.g., optimizing the dispatch of NPC generation and/or
buying directly from the market).
|
Both of the ESPs reflect the Utilities’ strategies, embedded in their filed IRPs, to minimize
supply and price risk through acquisition or construction of company owned generating resources in
the intermediate term (e.g., peaking capacity at Clark Generating Station; Tracy combined cycle
addition), forward contracts to meet capacity needs in the shorter term, and pursuit of fuel
diversity options such as coal and renewables in the longer term.
Long Term Purchase Power Activities
The Utilities update their long-term energy supply plans on an annual basis in concert with
the preparation of their respective ESPs, which are described in the preceding section. As noted
above, the ESPs serve as a guide for near-term execution and fulfillment of energy needs. When the
energy supply plans call for contracts of duration more than three years, requests for proposals
are issued, bids are evaluated, and contracts are executed with the successful bidders. Those
contracts are submitted to the PUCN for approval through an amended IRP.
As noted in the preceding section, the Utilities have reduced their longer-term needs for
power from those in prior years. The Utilities have not entered into a long-term purchase
agreement for conventional power since 2003. Currently, NPC has approximately 1,329 MW of long
term contracts with various providers, terms and expiration dates, and 305 MWs of long term
contracts with Qualifying Facilities. SPPC currently has 83 MWs of long term contracts which
expire by 2009.
The Utilities also entered into long-term contracts with renewable energy providers.
Short-Term Resource Optimization Strategy
The Utilities’ short-term resource optimization strategy involves both day-ahead (next day
through the end of the current month) and real-time (next hour through the end of the current day)
activities that require buying, selling and scheduling power resources to determine the most
economical way to produce or procure the power resources needed to meet the retail customer load
and operating reserve requirement. The Utilities commit and dispatch generating units based on the
comparative economics of generation versus spot-market purchase opportunities. Any amount of
excess capacity or energy is sold on the wholesale market, while any deficient capacity or energy
position is filled by either buying on the spot market or utilizing available generating capacity.
The day-ahead resource optimization begins with an analysis of projected hourly loads,
existing resources, and operating reserve requirements. Firm forward take-or-pay contracts are
scheduled and counted towards meeting the capacity needs of the day being pre-scheduled. The
day-of resource optimization involves minimizing system production costs each hour by lowering or
raising generating unit output or buying power and/or selling excess power in the wholesale market
all in order to meet the system load
59
requirement and operating reserve requirement. Any sale of
excess power priced above the incremental cost of producing such power reduces the net production
cost of operating the electrical system and thereby benefits the end use customer. The Utilities
endeavor to reduce the electrical systems’ net production cost by selling available excess energy
when it exists.
Real-time resource optimization requires an hourly determination of whether to increase or
decrease the loading of on-line generating units, commit previously off-line generating units,
un-commit on-line generating units, sell excess power, or purchase power in the real-time market to
meet the companies’ resource needs. In order to achieve the lowest production cost, the projected
incremental or decremental cost of the next available generation resource options is compared to
determine the lowest cost option.
Additional generating assets are expected to result in an uncommitted long peak position
during the shoulders months. This will present resource procurement with the opportunity to
implement a more active asset optimization strategy.
NEVADA POWER COMPANY
RESULTS OF OPERATIONS
NPC recognized net income of $224.5 million in 2006 compared to net income of $132.7 million
in 2005 and $104.3 million in 2004. NPC’s operating results for 2006 improved over 2005 primarily
as a result of the July 2006, Nevada Supreme Court ruling which allows NPC to recover the
approximate $180 million of the previously disallowed deferred energy costs and the carrying charge
associated with the Lenzie generating station, partially offset by increased interest expense.
NPC’s operating results for 2005 improved over 2004 primarily as a result of an increase in
operating income, as discussed in detail below, an increase in Allowance for Other Funds Used
During Construction and Allowance for Borrowed Funds During Construction and lower interest costs.
In 2006, NPC paid $35.8 million in dividends to SPR and declared an additional $13.5 million
dividend. In 2005, NPC paid and declared common stock dividends of $35.3 million to SPR.
Gross margin is presented by NPC in order to provide information by segment that management
believes aids the reader in determining how profitable the electric business is at the most
fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance
with SEC rules, provides a measure of income available to support the other operating expenses of
the business and is utilized by management in its analysis of its business.
NPC believes presenting gross margin allows the reader to assess the impact of NPC’s
regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin,
as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and
natural gas supply costs versus the fixed rates collected from customers. While these fluctuating
costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the
costs cannot be passed through to customers. Gross margin, which NPC calculates as operating
revenues less fuel and purchased power costs, provides a measure of income available to support the
other operating expenses of NPC. Gross margin changes based on such factors as general base rate
adjustments (which are required to be filed by statute every two years) and reflect NPC’s strategy
to increase internal power generation versus purchased power, which generates no gross margin.
60
The components of gross margin for the years ended December 31 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
|
2006
|
|
|
Prior Year %
|
|
|
2005
|
|
|
Prior Year %
|
|
|
2004
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
2,124,081
|
|
|
|
12.8
|
%
|
|
$
|
1,883,267
|
|
|
|
5.6
|
%
|
|
$
|
1,784,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power
|
|
|
764,850
|
|
|
|
-20.6
|
%
|
|
|
963,888
|
|
|
|
26.1
|
%
|
|
|
764,347
|
|
|
Fuel for power generation
|
|
|
552,959
|
|
|
|
99.6
|
%
|
|
|
277,083
|
|
|
|
17.7
|
%
|
|
|
235,404
|
|
|
Deferral of energy costs disallowed
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
-100.0
|
%
|
|
|
1,586
|
|
|
Deferral of energy costs-net
|
|
|
92,322
|
|
|
|
-302.2
|
%
|
|
|
(45,668
|
)
|
|
|
-133.6
|
%
|
|
|
135,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,410,131
|
|
|
|
18.0
|
%
|
|
$
|
1,195,303
|
|
|
|
5.1
|
%
|
|
$
|
1,137,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin before reinstatement of
Deferred Energy
|
|
$
|
713,950
|
|
|
|
3.8
|
%
|
|
$
|
687,964
|
|
|
|
6.4
|
%
|
|
$
|
646,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reinstatement of Deferred Energy
|
|
$
|
178,825
|
|
|
|
N/A
|
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin after reinstatement of
Deferred Energy
|
|
$
|
892,775
|
|
|
|
29.8
|
%
|
|
$
|
687,964
|
|
|
|
6.4
|
%
|
|
$
|
646,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The causes for significant changes in specific lines comprising the results of operations
for NPC for the respective years ended are provided below (dollars in thousands except for amounts
per unit).
Electric Operating Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
from Prior
|
|
|
|
|
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
year
|
|
|
Amount
|
|
|
Electric Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
975,568
|
|
|
|
18.5
|
%
|
|
$
|
823,095
|
|
|
|
7.9
|
%
|
|
$
|
762,907
|
|
|
Commercial
|
|
|
442,477
|
|
|
|
12.0
|
%
|
|
|
395,016
|
|
|
|
6.1
|
%
|
|
|
372,271
|
|
|
Industrial
|
|
|
631,762
|
|
|
|
12.8
|
%
|
|
|
560,059
|
|
|
|
5.7
|
%
|
|
|
529,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Revenues
|
|
|
2,049,807
|
|
|
|
15.3
|
%
|
|
|
1,778,170
|
|
|
|
6.8
|
%
|
|
|
1,665,094
|
|
|
Other
1
|
|
|
74,274
|
|
|
|
-29.3
|
%
|
|
|
105,097
|
|
|
|
-11.7
|
%
|
|
|
118,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
2,124,081
|
|
|
|
12.8
|
%
|
|
$
|
1,883,267
|
|
|
|
5.6
|
%
|
|
$
|
1,784,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail sales in thousands
of megawatt-hours (MWh)
|
|
|
20,820
|
|
|
|
7.0
|
%
|
|
|
19,455
|
|
|
|
4.6
|
%
|
|
|
18,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average retail revenue per MWh
|
|
$
|
98.45
|
|
|
|
7.7
|
%
|
|
$
|
91.40
|
|
|
|
2.1
|
%
|
|
$
|
89.49
|
|
|
|
|
|
1
|
Primarily wholesale, as discussed below
|
NPC’s retail revenues increased in 2006 compared to 2005 due to increases in retail
rates, customer growth and weather. Retail rates increased as a result of NPC’s various Base Tariff
Energy Rate (BTER) and deferred energy cases (see “Regulatory Proceedings”). Residential,
commercial and industrial customers increased by 4.9%, 5.1% and 4.3%, respectively. Customer usage
increased due to colder winter weather and hotter spring weather. Based on NPC’s projected
customer forecast, NPC expects retail electric customers in the Clark County area to continue to
grow in 2007.
In November 2006, NPC filed its General Rate Case with the PUCN. The filing requests an
overall rate increase, with rates to be effective June 1, 2007. In January 2007, NPC filed its
annual deferred energy filing and an application to request recovery of deferred legal and
settlement costs incurred for terminated power contracts executed during the Western Energy Crisis.
If approved by the PUCN, the overall effect of both filings would be a slight decrease in rates.
NPC requested that the rates become effective on June 1, 2007. A decision on these cases is
expected in the Spring of 2007. For further discussion on the various cases see Regulatory
Proceedings, later.
61
NPC’s retail revenues were higher in 2005 compared to 2004 primarily due to customer growth
and higher rates. Increases in the number of residential, commercial and industrial customers were
5.5%, 5.7% and 3.8%, respectively. Higher rates became
effective in April 2004, which were the result of NPC’s 2003 General and Deferred Rate Cases
and October 2005, as a result of NPC’s 2005 BTER Update. These increases were slightly offset by a
decrease resulting from NPC’s 2004 Deferred Energy Rate Case effective April 2005.
Electric Operating Revenues — Other decreased in 2006 compared to 2005, primarily due to
revenues associated with Mohave which have been reclassified to Other Regulatory Assets as a result
of the shut down of the Mohave Generating Station. For further discussion on Mohave refer to Note
13, Commitments and Contingencies in the Notes to Financial Statements. Also contributing to the
decrease was a decrease in transmission revenues as a result of the purchase of Silverhawk. In
2005, the previous owner of Silverhawk used NPC’s transmission system to distribute electricity
from the facility.
The decrease in Electric Operating Revenues — Other in 2005 compared to 2004 was primarily due
to certain types of transactions that were reported in revenues for 2004, which are now netted in
purchased power. The decrease also included decreased energy usage by Public Authority customers
due to their transitioning to distribution only services by purchasing their energy from other
sources, as allowed by Nevada law under certain circumstances. Partially offsetting this decrease
was a refund in 2004 of $5.9 million owed to transmission customers as a result of FERC’s approval
of a tariff agreement in July 2004. For further discussion on the Transmission case see Note 3,
Regulatory Actions of the Notes to Financial Statements. The tariff agreement also lowered the
transmission rates which contributed to the decrease in 2005 revenues.
Purchased Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Amount
|
|
Prior Year
|
|
Amount
|
|
Prior Year
|
|
Amount
|
|
Purchased Power
|
|
$
|
764,850
|
|
|
|
-20.6
|
%
|
|
$
|
963,888
|
|
|
|
26.1
|
%
|
|
$
|
764,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power in thousands
of MWh
|
|
|
10,248
|
|
|
|
-20.5
|
%
|
|
|
12,894
|
|
|
|
4.7
|
%
|
|
|
12,319
|
|
|
Average cost per MWh of
Purchased power
|
|
$
|
74.63
|
|
|
|
-0.2
|
%
|
|
$
|
74.75
|
|
|
|
20.5
|
%
|
|
$
|
62.05
|
|
NPC’s purchased power costs decreased in 2006 compared to 2005, primarily due to an
increase in internal generation with the addition of the Silverhawk and Lenzie plants. As a
result, the volume of MWh purchased decreased compared to the prior year.
NPC’s purchased power costs increased in 2005 compared to 2004, due to higher prices and
increased volume. NPC’s energy contracts calculate prices using gas indexes; therefore, higher
natural gas prices in 2005 increased the price of purchased power. Furthermore, purchased power
costs were higher due to gas tolling agreements entered into during the second quarter of 2004 and
June 2005. These gas tolling agreements are purchased power agreements where NPC provides natural
gas to the supplier who generates the energy for NPC. The gas tolling agreements are based on gas
indexes; therefore, the increase in natural gas prices increased the cost of purchased power.
Volume increased because NPC satisfied more of its native load requirements through purchased power
rather than generation.
Fuel for Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Fuel for Power Generation
|
|
$
|
552,959
|
|
|
|
99.6
|
%
|
|
$
|
277,083
|
|
|
|
17.7
|
%
|
|
$
|
235,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thousands of MWhs generated
|
|
|
12,160
|
|
|
|
50.2
|
%
|
|
|
8,094
|
|
|
|
-4.4
|
%
|
|
|
8,470
|
|
|
Average fuel cost per MWh
of Generated Power
|
|
$
|
45.47
|
|
|
|
32.8
|
%
|
|
$
|
34.23
|
|
|
|
23.2
|
%
|
|
$
|
27.79
|
|
Fuel for power generation increased in 2006 as compared to 2005 due to several factors:
|
|
•
|
|
With the addition of Silverhawk and Lenzie it was more economical for NPC to rely on its
own generation rather than the purchase of power. As a result, the increase in volume of
MWh’s generated increased significantly compared to the prior year.
|
62
|
|
•
|
|
The shutdown of Mohave as of the beginning of the year increased the cost per MWh of
generated power. Although Silverhawk and Lenzie are highly efficient generation stations,
the cost of coal is substantially lower than the cost of natural gas. Mohave generation
during 2005 represented approximately 17% of total generation.
|
|
|
|
|
•
|
|
Hedging instruments purchased when gas prices were escalating as a result of the 2005
hurricanes in the southern United States increased fuel for power generation costs. The
settlement of these instruments during 2006 negatively impacted the average cost per MWh as
natural gas prices were decreasing during this period.
|
Fuel for power generation costs increased in 2005 as compared to 2004 due to the increased
price of natural gas. The decrease in volume of generation was primarily due to NPC satisfying more
of its native load requirements through purchased power rather than generation. The increase in
average unit fuel cost per megawatt-hour was primarily due to higher gas costs in 2005 compared to
2004.
Deferral of Energy Costs — Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Reinstatement of deferred energy
|
|
$
|
(178,825
|
)
|
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
$
|
—
|
|
|
Deferred energy costs disallowed
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
1,586
|
|
|
Deferral of energy costs-net
|
|
|
92,322
|
|
|
|
N/A
|
|
|
|
(45,668
|
)
|
|
|
N/A
|
|
|
|
135,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(86,503
|
)
|
|
|
|
|
|
$
|
(45,668
|
)
|
|
|
|
|
|
$
|
137,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reinstatement of deferred energy represents the July 2006 decision by the Nevada Supreme
Court which ruled that NPC is allowed to recover approximately $180 million of previously disallowed deferred energy and
directed the District Court to remand the issue back to the PUCN to determine the rate schedule
that will be used to recover this amount. In all other respects, the Nevada Supreme Court affirmed
the District Court’s decision on the PUCN disallowance. As a result of the Nevada Supreme Court
decision, NPC recorded approximately $180 million before tax, of the previously disallowed deferred
energy in its Consolidated Income Statement as “Reinstatement of Deferred Energy.” See Regulatory
Proceedings, for further discussion of the $180 million of deferred energy.
Deferred energy costs disallowed for 2004 reflect the first quarter write-off of $1.6 million
in electric deferred energy costs incurred during the twelve months ended September 30, 2003, that
were disallowed by the PUCN in their March 2004 decision in NPC’s deferred energy rate case.
Deferred energy costs — net represent the difference between actual fuel and purchased power
costs incurred during the period and amounts recoverable through current rates. To the extent
actual costs exceed amounts recoverable through current rates, the excess is recognized as a
reduction in costs. Conversely to the extent actual costs are less than amounts recoverable
through current rates, the difference is recognized as an increase in costs. Deferred energy costs
- net also include the current amortization of fuel and purchased power costs previously deferred.
See Note 1, Summary of Significant Accounting Policies, Deferral of Energy Costs of Notes to
Financial Statements for further detail of deferred energy balances.
Amounts for 2006, 2005 and 2004 include amortization of deferred energy costs of $120.5
million, $131.5 million and $228.8 million, respectively; and under-collections of amounts
recoverable in rates of $28.2 million, $177.1 million and $92.7 million, respectively.
63
Allowance for Funds Used During Construction (AFUDC)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Allowance for other funds used
during construction
|
|
$
|
11,755
|
|
|
|
-37.1
|
%
|
|
$
|
18,683
|
|
|
|
341.7
|
%
|
|
$
|
4,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for borrowed funds used
during construction
|
|
|
11,614
|
|
|
|
-49.9
|
%
|
|
|
23,187
|
|
|
|
304.1
|
%
|
|
|
5,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23,369
|
|
|
|
-44.2
|
%
|
|
$
|
41,870
|
|
|
|
320.0
|
%
|
|
$
|
9,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AFUDC for NPC was lower in 2006 compared to 2005 due to a decrease in Construction Work
in Progress (CWIP) balance on which AFUDC is calculated. The decrease in the average CWIP balance
was primarily due to the completion of Blocks 1 and 2 of the Chuck Lenzie Station and Harry Allen
Unit 4 in early spring of 2006.
AFUDC was higher in 2005 compared to 2004 due to the construction of Blocks 1 and 2 of the
Lenzie Generating Station.
Other (Income) and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Other operating expense
|
|
$
|
218,120
|
|
|
|
3.4
|
%
|
|
$
|
211,039
|
|
|
|
14.9
|
%
|
|
$
|
183,736
|
|
|
Maintenance expense
|
|
$
|
61,899
|
|
|
|
18.9
|
%
|
|
$
|
52,040
|
|
|
|
-8.7
|
%
|
|
$
|
57,030
|
|
|
Depreciation and amortization
|
|
$
|
141,585
|
|
|
|
14.1
|
%
|
|
$
|
124,098
|
|
|
|
4.4
|
%
|
|
$
|
118,841
|
|
|
Interest charges on long-term debt
|
|
$
|
171,188
|
|
|
|
7.6
|
%
|
|
$
|
159,106
|
|
|
|
4.2
|
%
|
|
$
|
152,764
|
|
|
Interest for energy suppliers
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
(14,825
|
)
|
|
|
-38.7
|
%
|
|
$
|
(24,171
|
)
|
|
Interest charges-other
|
|
$
|
17,038
|
|
|
|
25.6
|
%
|
|
$
|
13,563
|
|
|
|
-6.7
|
%
|
|
$
|
14,533
|
|
|
Carrying charge for Lenzie
|
|
$
|
(33,440
|
)
|
|
|
N/A
|
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
—
|
|
|
Interest accrued on deferred energy
|
|
$
|
(21,902
|
)
|
|
|
7.6
|
%
|
|
$
|
(20,350
|
)
|
|
|
0.7
|
%
|
|
$
|
(20,199
|
)
|
|
Other income
|
|
$
|
(16,992
|
)
|
|
|
-33.7
|
%
|
|
$
|
(25,626
|
)
|
|
|
12.2
|
%
|
|
$
|
(22,844
|
)
|
|
Disallowed merger costs
|
|
|
|
|
|
|
N/A
|
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
3,961
|
|
|
Other expense
|
|
$
|
8,480
|
|
|
|
-0.5
|
%
|
|
$
|
8,525
|
|
|
|
27.9
|
%
|
|
$
|
6,665
|
|
Other operating expense increased in 2006 compared to 2005 due to various costs all of
which were not individually significant. These increases were partially offset by a decrease in
legal fees and operating expense related to Mohave, Reid Gardner and Clark compared to 2005.
Other operating expense increased for 2005 compared to 2004 primarily due to increased
advisory fees, amortization of regulatory assets and severance costs associated with the
reorganization of SPPC, NPC and SPR.
The increase in Maintenance expense in 2006 compared to 2005 was primarily due to the addition
of Lenzie and Silverhawk Generating Stations in 2006; partially offset by reduced maintenance
expenses for Mohave and Navajo.
The decrease in Maintenance expense in 2005 compared to 2004 was due to the timing of
scheduled and unscheduled plant maintenance at Clark Station, Reid Gardner and Navajo during 2004.
Depreciation and amortization increased in 2006 compared to 2005 primarily as a result of
increases in plant-in-service. The increase is primarily due to the purchase of Silverhawk and
completion of the Harry Allen Unit IV. The increase in depreciation and amortization expense
between 2005 and 2004 was the result of routine increases to plant-in-service to serve regular
system growth.
Interest charges on Long-Term Debt increased for the year ended December 31, 2006, compared to
2005 due primarily to the issuance in January 2006 of $210 million Series M, General and Refunding
Mortgage Notes and the use of the Revolving Credit Facility, partially offset by various
refinancings of debt at lower interest rates. The $210 million was issued to fund the
acquisition of the Silverhawk Generating Facility. Interest charges related to this issuance was
approximately $11.9 million. NPC’s use of the Revolving Credit Facility increased in 2006 primarily
due to increased capital expenditures and fuel and purchase power expenses. Interest expense for
the Revolving Credit Facility was approximately $12 million compared to $1.9 million in the prior
year.
64
Interest charges on Long-Term Debt increased slightly for the year ended December 31, 2005,
compared to 2004 due primarily to increases in long-term debt balances related to new debt issued
in November 2004 of $250 million, interest associated with various draws from the Long-Term Credit
Facility in 2005, and an increase in interest rates on NPC’s $115 million variable rate interest
notes in 2005. This increase was partially offset by debt redemptions, in July 2005 of $87.5
million and $122.5 million. See Note 6, Long-Term Debt of the Notes to Financial Statements for
additional information regarding long-term debt.
NPC’s interest charges for energy suppliers are comprised of interest accruals for terminated
supplier balances that had been subject to litigation. The amount reported in 2005 includes
reversals of accrued balances due to settlements reached with suppliers. The amount reported in
2004 includes the reversal of $28 million resulting from a ruling by the U.S. District Court that
lowered the interest rate previously accrued. See Note 13, Commitments and Contingencies of the
Notes to Financial Statements, for more information regarding the Enron litigation.
NPC’s interest charges-other increased for the year ended December 31, 2006 when compared to
the same period in 2005, due to higher costs related to new debt issues and redemptions. Interest
charges-other for the year ended December 31, 2005 decreased compared to the same period in 2004
following reduced charges related to NPC’s short-term credit facilities. These costs were offset
with additional costs associated with the debt redemption of $210 million in July 2005. See Note
6, Long-Term Debt of the Notes to Financial Statements, for additional information regarding
long-term debt.
NPC’s carrying charges on Lenzie for the year ended December 31, 2006 represent carrying
charges earned on the incurred debt component of the acquisition and construction costs of the
completed Lenzie Generating Station. The PUCN authorized NPC to
accrue a carrying charge for the cost of acquisition and construction until the plant is
included in rates. See Note 1 of the Notes to Financial Statements for discussion of the
accounting for the carrying charge for Lenzie.
NPC’s Interest accrued on deferred energy for the year ended December 31, 2006, were slightly
higher than the same period in 2005 due to slightly higher average deferred energy balances during
2006, excluding deferred energy assets of $179 million associated with the Nevada Supreme Court
decision reversing the deferred energy costs disallowance. NPC’s interest accrued on deferred
energy costs was comparable for 2005 to 2004. See Note 3, Regulatory Actions of the Notes to
Financial Statements for further discussion of deferred energy accounting issues and Note 13,
Commitments and Contingencies of the Notes to Financial Statements for further discussion of the
Nevada Supreme Court decision.
Disallowed merger costs for the year ended December 31, 2004 were a result of the PUCN
decision in NPC’s 2003 General Rate Case. The PUCN decision permitted substantially all of the
merger costs that NPC requested recovery of, except for a 20% reduction in merger costs that were
to be amortized over the next two years. Also included in the write-off are merger costs allocable
to non-Nevada jurisdictional sales that NPC had determined not to be recoverable in rates. See
“Regulatory Proceedings” — and Note 3, Regulatory Actions of the Notes to Financial Statements, for
additional information regarding NPC’s recovery of merger costs.
NPC’s Other income decreased for the year ended December 31, 2006 compared to the same period
in 2005 due primarily to the lower amortization of gains associated with disposition of SO2
allowances and the expiration of the amortization associated with the disposition of property
offset slightly by higher interest income. NPC’s Other income slightly increased for the year
ended December 31, 2005 compared to the same period in 2004 due to higher interest income offset by
lower amortization of gains associated with disposition of SO2 allowances.
NPC’s Other expense was comparable for 2006 to 2005. NPC’s Other expense increased for the
year ended December 31, 2005 compared to the same period in 2004 due primarily to higher expenses
associated with corporate advertising, lobbying activities, and various other charges, all of which
were not individually significant.
ANALYSIS OF CASH FLOWS
NPC’s cash flows increased during the year ended December 31, 2006, compared to the same
period in 2005, due to an increase in cash from financing activities, a slight increase in cash
from operating activities offset partially by an increase in use of cash by investing activities.
At
various times during 2006, NPC borrowed a total of $710 million under its revolving credit
facility and repaid a total of $860 million, including $150 million borrowed in 2005, using the net
proceeds of issuance of $905 million of NPC’s General and
Refunding Mortgage Notes, Series M, N and
O and a $200 million capital contribution from SPR. The remainder of the proceeds, together with
the draw on the credit facility and cash from operations, was utilized to redeem approximately $563
million of outstanding debt and to pay associated costs and to finance net construction costs of
$627 million. NPC also refinanced $92.5 million of Revenue Bonds with newly issued auction rate
Revenue Bonds during 2006. In 2006, SPR contributed capital of $200 million to NPC and NPC paid
dividends to SPR of approximately $35.8 million.
Cash used by investing activities increased in 2006 when compared to 2005 primarily due to the
acquisition of Silverhawk and improvements at other generating stations, offset by a reduction in
spending at the Lenzie plant that was placed in service in 2006.
65
Cash from operations increased during 2006 when compared to 2005 due to rate increases for
deferred energy and a decrease in accounts receivable, offset by a decrease in collections for
deferred energy balances due to the ending of collection periods and a reduction in accounts
payable primarily associated with purchase power suppliers. The increase was also offset by the
settlement with Enron.
NPC’s cash flows decreased during the year ended December 31, 2005, compared to the same
period in 2004, as a result of an increase in cash used for investing activities and by decreases
in cash flows from operating and financing activities. Cash used in investing activities increased
mainly due to an increase in utility construction for the Chuck Lenzie project under construction
in 2005. The decrease in cash from operating activities is primarily due to energy costs being
higher than amounts recovered in rates in 2005 and changes in accounts receivable for tax sharing
agreements. Also partially offsetting the decrease in cash from operating activities was the $49
million escrow payment for Enron in 2004, and a reduction in prepayments and deposits for energy in
2005 due to the establishment of the revolving credit facility. Cash from financing activities
decreased in 2005 due to a reduction in debt issued in 2005, offset by additional investments from
the parent company and lower dividend payments. NPC was able to retire $210 million of high yield
notes in the third quarter utilizing the majority of a $230 million equity contribution from SPR,
per the equity claw-back provisions of the note.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
NPC’s primary source of operating cash flows is electric revenues, including the recovery of
previously deferred energy costs. Significant uses of cash flows from operations include the
purchase of electricity and natural gas, other operating expenses and the payment of interest on
NPC’s outstanding indebtedness.
|
|
|
|
|
|
|
Available Liquidity as of December 31, 2006 (in millions)
|
|
|
|
|
NPC
|
|
|
Cash and Cash Equivalents
|
|
$
|
36.6
|
|
|
Balance available on Revolving Credit Facility
|
|
|
545.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Available Liquidity
1
|
|
$
|
581.6
|
|
|
|
|
|
|
|
|
|
|
1
|
As of February 23, 2007, NPC had approximately $476.3
million available under its revolving credit facility.
|
In August 2006, SPR contributed capital to NPC of approximately $200 million. NPC used
the proceeds to repay indebtedness under its revolving credit facility. There were no other capital
contributions from SPR to NPC in 2006.
In 2006, NPC paid $35.8 million in dividends to SPR and declared an additional $13.5 million
dividend. In January 2007, NPC paid the $13.5 million dividend to SPR.
NPC anticipates that it will be able to meet operating costs, such as fuel and purchased power
costs, with internally generated funds, including the recovery of deferred energy and external
borrowings. However, to fund capital requirements, as discussed below, NPC may be required to meet
such financial obligations with a combination of internally generated funds, the use of its
revolving credit facility and if necessary, the issuance of long-term debt. Additional liquidity
beyond the amount indicated in the footnote above would come from a capital contribution from SPR,
or through additional financing authority granted by an order of the PUCN, requested through the
submittal of a financing application.
NPC’s overall liquidity continued to improve in 2006. NPC’s revolving credit facility was
increased to $600 million in April, 2006, providing $100 million of additional liquidity for
increased commodity prices. NPC’s debt profile improved as a result of refinancing more than $668
million of long-term debt. These refinancings are expected to reduce future interest expense.
NPC designs operating and capital budgets to control operating costs and capital expenditures.
In addition to operating expenses, NPC has continuing commitments for capital expenditures for
construction, improvement and maintenance of facilities.
Detailed below are NPC’s Capital Structure, Capital Requirements, Contractual Obligations,
recently completed Financing Transactions and Factors Affecting Liquidity including our ability to
obtain debt on favorable terms and limitations on indebtedness.
66
Capital Structure
NPC’s actual consolidated capital structure was as follows at December 31 (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
Current Maturities of Long-Term Debt
|
|
$
|
5,948
|
|
|
|
0.1
|
%
|
|
$
|
6,509
|
|
|
|
0.2
|
%
|
|
Long-Term Debt
|
|
|
2,380,139
|
|
|
|
52.2
|
%
|
|
|
2,214,063
|
|
|
|
55.6
|
%
|
|
Common Equity
|
|
|
2,172,198
|
|
|
|
47.7
|
%
|
|
|
1,762,089
|
|
|
|
44.2
|
%
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,558,285
|
|
|
|
100
|
%
|
|
$
|
3,982,661
|
|
|
|
100
|
%
|
|
|
|
|
|
|
Capital Requirements
Construction Expenditures
NPC’s cash construction expenditures have increased since 2004 and are expected to continue to
increase due to programs designed to meet electric load growth and reliability needs. Cash
construction expenditures for the years ended 2006, 2005 and 2004 were approximately $627.0
million, $478 million, and $454 million, respectively. NPC’s cash requirement for construction
expenditures for 2007 are projected to be $980.1 million. NPC’s cash requirement for construction
expenditures for 2007 through 2011 are projected to be $5.9 billion. To fund these capital
projects NPC may meet such financial obligations with a combination of internally generated funds,
the use of its revolving credit facility, the issuance of long-term debt, and if necessary, capital
contributions from SPR. Depending on the progress of the Ely Energy Center, the timing and extent
of the estimated capital expenditures necessary may change.
Contractual Obligations
The table below provides NPC’s consolidated contractual obligations, not including estimated
construction expenditures described above, as of December 31, 2006, that NPC expects to satisfy
through a combination of internally generated cash and, as necessary, through the issuance of
short-term and long-term debt (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment Due by Period
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Thereafter
|
|
|
Total
|
|
|
Long-Term Debt Maturities
|
|
$
|
5,948
|
|
|
$
|
7,068
|
|
|
$
|
22,138
|
|
|
$
|
7,843
|
|
|
$
|
369,734
|
|
|
$
|
1,986,113
|
|
|
$
|
2,398,844
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt Interest Payments
|
|
|
153,962
|
|
|
|
154,367
|
|
|
|
154,228
|
|
|
|
153,812
|
|
|
|
136,782
|
|
|
|
1,261,214
|
|
|
|
2,014,365
|
|
|
Purchased Power
|
|
|
310,988
|
|
|
|
257,739
|
|
|
|
239,361
|
|
|
|
244,305
|
|
|
|
242,671
|
|
|
|
2,868,242
|
|
|
|
4,163,306
|
|
|
Coal and Natural Gas
|
|
|
250,201
|
|
|
|
62,833
|
|
|
|
50,075
|
|
|
|
47,107
|
|
|
|
34,438
|
|
|
|
183,550
|
|
|
|
628,204
|
|
|
Long -Term
Service Agreements(1)
|
|
|
15,979
|
|
|
|
13,867
|
|
|
|
24,267
|
|
|
|
22,037
|
|
|
|
12,148
|
|
|
|
123,783
|
|
|
|
212,081
|
|
|
Southern Operations Center Lease
|
|
|
875
|
|
|
|
3,000
|
|
|
|
3,075
|
|
|
|
3,180
|
|
|
|
3,260
|
|
|
|
65,320
|
|
|
|
78,710
|
|
|
Operating Leases
|
|
|
6,525
|
|
|
|
7,146
|
|
|
|
6,253
|
|
|
|
5,161
|
|
|
|
3,441
|
|
|
|
64,459
|
|
|
|
92,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Cash Obligations
|
|
$
|
744,478
|
|
|
$
|
506,020
|
|
|
$
|
499,397
|
|
|
$
|
483,445
|
|
|
$
|
802,474
|
|
|
$
|
6,552,681
|
|
|
$
|
9,588,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Does not include equipment and services contracts related to
the new peaking units at Clark Generating Station, entered into in
February 2007.
|
Pension Plan Matters
SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC.
The annual net benefit cost for the plan is expected to decrease in 2007 by approximately $1.3
million compared to the 2006 cost of $30.6 million. As of September 30, 2006, the measurement date,
the plan was fully funded on a FAS 87 ABO basis (fair value of assets exceeded ABO). During 2006,
SPR contributed a total of $16 million to meet its funding obligations under the plan. At the
present time it is not expected that any additional funding will be required in 2007 to meet the
minimum funding level requirements defined by the Pension Benefit Guaranty Corporation and ERISA.
However, SPR and the Utilities currently expect to contribute an amount similar to the 2006
funding. The amounts to be contributed may change subject to market conditions.
67
Financing Transactions
Pollution Control Refunding Revenue Bonds, Series 2006, 2006A and 2006B
In August 2006, on behalf of NPC, Clark County, Nevada (Clark County) issued $39.5 million
aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006, due
January 2036. On the same date, on behalf of NPC, Coconino County, Arizona Pollution Control
Corporation (Coconino County) issued $40 million aggregate principal amount of its Pollution
Control Refunding Revenue Bonds, Series 2006A, due September 2032, and $13 million aggregate
principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006B, due March 2039.
In connection with the issuance of these Bonds, NPC entered into financing agreements with
Clark County and Coconino County, pursuant to which Clark County and Coconino County loaned the
proceeds from the sales of the bonds to NPC. NPC’s payment obligations under the financing
agreements are secured by NPC’s General and Refunding Mortgage Notes, Series P.
The interest rates of the Bonds were initially determined by an auction. The method of
determining the interest rate on the Bonds may be converted from time to time so that such Bonds
would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.
The proceeds of the offerings were used to refund the following bonds, all of which were
previously issued for the benefit of NPC:
|
|
•
|
|
$39.5 million principal amount of 6.60% Clark County’s Pollution Control Refunding
Revenue Bonds, Series 1992B,
|
|
|
|
|
•
|
|
$20 million principal amount of 6.375% Coconino County’s Pollution Control Revenue Bonds, Series 1996,
|
|
|
|
|
•
|
|
$20 million principal amount of 5.80% Coconino County’s Pollution Control Revenue Bonds, Series 1997B, and
|
|
|
|
|
•
|
|
$13 million principal amount of 5.35% Coconino County’s Pollution Control Refunding
Revenue Bonds, Series 1995E.
|
General and Refunding Mortgage Notes, Series O
On May 12, 2006, NPC issued and sold $250 million in aggregate principal amount of 6.5%
General and Refunding Mortgage Notes, Series O, due 2018. The Series O Notes were issued with
registration rights. Proceeds of the offering, together with available cash, were utilized to:
|
|
•
|
|
fund the early redemption of $78 million aggregate principal amounts of NPC’s 7.2%
Industrial Development Revenue Bonds, Series 1992 C, due 2022,
|
|
|
|
|
•
|
|
fund the early redemption, in June 2006, of approximately $72.2 million aggregate
principal amount of NPC’s 7.75% Junior Subordinated Debentures due 2038 (when the
debentures were repaid upon redemption, the proceeds from the repayment were used to
simultaneously redeem an equal amount of the 7.75% Cumulative Quarterly Preferred
Securities of NVP Capital III, a wholly-owned subsidiary of NPC),
|
|
|
|
|
•
|
|
repay amounts outstanding under NPC’s revolving credit facility.
|
In June 2006, NPC issued an additional $75 million in aggregate principal amount of its 6.5%
General and Refunding Mortgage Notes, Series O, as part of the same series as the original Series O
Notes. The aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due
2018, outstanding is $325 million as of December 31, 2006. The proceeds from the second issuance,
along with the proceeds from an offering of $120 million of NPC’s 6.65% General and Refunding
Mortgage Notes, Series N, due 2036 (described below) were used to pay the total consideration for
the tender offer for the 10.875% General and Refunding Mortgage Notes, Series E, described below.
General and Refunding Mortgage Notes, Series N
In April 2006, NPC issued and sold $250 million of its 6.65% General and Refunding Mortgage
Notes, Series N, due April 2036. The Series N Notes were issued with registration rights. Proceeds
of the offering, together with available cash, were utilized to:
|
|
•
|
|
fund the early redemption of $35 million aggregate principal amount of NPC’s 8.50%
Series Z First Mortgage Bonds due 2023 plus approximately $1 million of associated
redemption premiums,
|
|
|
|
|
•
|
|
fund the early redemption of $105 million aggregate principal amount of 6.70%
Industrial Development Revenue Bonds, due 2022, and
|
|
|
|
|
•
|
|
fund the early redemption of approximately $122.5 million aggregate principal amount
of NPC’s 8.20% Junior Subordinated Debentures due 2037 (when the debentures were repaid
upon redemption, the proceeds from the repayment were used to simultaneously redeem an
equal amount of the 8.20% Cumulative Quarterly Preferred Securities of NVP Capital I, a
wholly-owned subsidiary of NPC).
|
68
In June 2006, NPC issued an additional $120 million in aggregate principal amount of its 6.65%
General and Refunding Mortgage Notes, Series N, as part of the same series as the original Series N
Notes. The aggregate principal amount of 6.65% General and Refunding Mortgage Notes, Series N, due
2036, outstanding is $370 million as of December 31, 2006. The proceeds from the second issuance,
along with the proceeds from an offering of $75 million of NPC’s 6.5% General and Refunding
Mortgage Notes, Series O, due 2018 (described above) were used to pay the total consideration for
the tender offer on the 10.875% General and Refunding Mortgage Notes, Series E, described below.
Tender Offer for General and Refunding Mortgage Notes, Series E
In June 2006, NPC commenced a tender offer for all of its 10.875% General and Refunding
Mortgage Notes, Series E, due 2009. In conjunction with that offer, NPC solicited the consent of
holders of a majority in aggregate principal amount of the Series E Notes to eliminate
substantially all of the restrictive covenants contained in the officer’s certificate governing the
Series E Notes. Approximately $150 million of $162.5 million Series E Notes outstanding were
validly tendered and accepted by NPC. Those holders who tendered the Series E Notes and delivered
their consents by June 2006 were entitled to receive a consent payment of $30 per $1,000 principal
amount of Series E Notes, plus tender consideration for each $1,000 principal amount of Series E
Notes validly tendered. Those holders who tendered the Series E Notes after June 14, 2006, but
prior to June 28, 2006, were entitled to receive the tender consideration only. This tender
consideration was $1,038.45 in cash plus accrued and unpaid interest up to the June 2006 settlement
date per $1,000 principal amount of the Series E Notes tendered. Proceeds from the June 2006
issuance of Series N and Series O Notes (discussed above) were used to fund the tender offer. The
total consideration (including the consent payment and accrued interest) paid in June 2006 was
approximately $163.6 million. In October 2006, NPC redeemed the remaining $12.6 million aggregate
principal amount of the Series E Notes, plus accrued interest, using available cash on hand.
Revolving Credit Facility
In April 2006, NPC increased the size of its second amended and restated revolving credit
facility expiring 2010 to $600 million. The facility will provide additional liquidity for
increased commodity prices and temporary bridge financing of capital expenditures. As of December
31, 2006, NPC had $55 million of letters of credit outstanding
and had no amounts borrowed under
the
revolving credit facility. As of February 23, 2007, NPC had $48.7 million of letters of
credit outstanding and $75 million borrowed under the revolving credit facility.
The NPC Credit Agreement contains two financial maintenance covenants. The first requires NPC
to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last
day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of
consolidated cash flow to consolidated interest expense, determined as of the last day of each
fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1.
As of December 31, 2006, NPC was in compliance with these covenants.
The NPC Credit Agreement provides for an event of default if there is a failure under NPC’s
other financing agreements to meet certain payment terms or to observe other covenants that would
result in an acceleration of payments due.
The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends.
These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions.
General and Refunding Mortgage Notes, Series M
In January 2006, NPC issued and sold $210 million of its 5.95% General and Refunding Mortgage
Notes, Series M, due March 2016. The Series M Notes were issued with registration rights. In
February 2006 the net proceeds of the issuance plus available cash were used to repay $210 million
of amounts outstanding under NPC’s revolving credit facility, which were borrowed to finance the
purchase of a 75% ownership interest in the Silverhawk Generating Facility.
Discharge of NPC’s First Mortgage Indenture
In August 2006, following the refunding of the $39.5 million aggregate principal amount of
Pollution Control Refunding Revenue Bonds (PCRBs), Series 1992B, (see above) the first mortgage
bonds which secured the PCRBs were retired.
In August 2006, NPC exchanged $115 million in aggregate principal amount of First Mortgage
Bonds, Series BB and Series CC, for $115 million in aggregate principal amount of General and
Refunding Mortgage Bonds, Series Q. The first mortgage bonds had been issued as security for the
$100 million Clark County, Nevada Industrial Development Refunding Revenue Bonds, Series 2000A, and
the $15 million Clark County, Nevada Pollution Control Refunding Revenue Bonds, Series 2000B.
With the conclusion of these two transactions, all of the bonds outstanding under the First
Mortgage Indenture were retired as of August 2006. Upon the satisfaction and discharge of the
First Mortgage Indenture in September 2006, NPC’s General and
69
Refunding Mortgage Indenture, dated
as of May 1, 2001, with the Bank of New York as Trustee, became the first priority lien on
substantially all of NPC’s utility property in Nevada.
Factors Affecting Liquidity
Limitations on Indebtedness
Certain factors impact NPC’s ability to issue debt:
|
|
1.
|
|
Financing Authority from the PUCN. In February 2006, NPC received PUCN
authorization to enter into financings of $1.78 billion, which amount included $600
million for the revolving credit facility (described above). NPC has issued
approximately $100 million of the new debt authorized under the PUCN Order. NPC’s only
remaining authority under this PUCN Order allows NPC to refinance its existing debt and
to use its $600 million revolving credit facility.
|
|
|
|
|
2.
|
|
Limits on Bondable Property. To the extent that NPC has the ability to issue debt
under the most restrictive covenants in its financing agreements and has financing
authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited
by the amount of bondable property or retired bonds that can be used to issue debt under
its General and Refunding Mortgage Indenture. As of December 31, 2006, NPC had the
capacity to issue $672 million of General and Refunding Mortgage Securities.
|
|
|
|
|
3.
|
|
Financial Covenants in its and SPR’s financing agreements. The terms of certain
SPR debt further prohibit NPC and SPPC from incurring additional indebtedness unless
certain conditions have been met. See SPR’s Limitations on Indebtedness for details of
these restrictions. In addition to the SPR debt, the terms of NPC’s Series G Notes,
which mature in 2013, NPC’s Series I Notes, which mature in 2012, NPC’s Series L Notes,
which mature in 2015, and NPC’s Second Amended and Restated Revolving Credit Facility
restrict NPC from incurring any additional indebtedness unless certain covenants are
satisfied (See Note 8, Debt Covenant and Other Restrictions). If NPC’s Series G Notes,
Series I Notes, or the Series L Notes are upgraded to investment grade by both Moody’s
and S&P, these restrictions will be suspended and will no longer be in effect so long as
the applicable series of securities remains investment grade.
|
As of December 31, 2006, the financial covenants under the revolving credit facility,
which are more restrictive than the Series G, I and L Notes restrictions, would allow NPC
to issue up to $2.1 billion of additional debt. The covenant limitations of certain SPR
debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and
NPC, of $2.1 billion as of December 31, 2006. However, since NPC currently has no PUCN
authority to issue new debt, NPC is limited to borrowing under its credit facility. As of
February 23, 2007, the balance available under the credit facility is $476.3 million.
Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s
debt covenant limitations may allow for higher or lower borrowings than $2.1 billion,
depending on the Utilities’ combined usage of their respective revolving credit facilities
at the time of the covenant calculation.
Limitations on Ability to Issue General and Refunding Mortgage Bonds
As of December 31, 2006, $2.7 billion of NPC’s General and Refunding Mortgage Securities were
outstanding. As mentioned in (2) above under “
Limitations on Indebtedness
”, additional securities
may be issued under the General and Refunding Mortgage Indenture as of December 31, 2006. That
amount is determined on the basis of:
|
|
1.
|
|
70% of net utility property additions
|
|
|
|
|
2.
|
|
the principal amount of retired General and Refunding Mortgage Securities, and/or
|
|
|
|
|
3.
|
|
the principal amount of first mortgage bonds retired after October 2001.
|
NPC also has the ability to release property from the lien of the General and Refunding
Mortgage Indenture on the basis of net property additions, cash and/or retired bonds. To the extent
NPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce
the amount of securities issuable under that indenture.
70
Credit Ratings
NPC is rated by four Nationally Recognized Statistical Rating Organizations, S&P, Moody’s,
Fitch, and DBRS. As of February 23, 2007, the ratings are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rating Agency
|
|
|
|
|
|
DBRS
|
|
Fitch
|
|
Moody’s
|
|
S&P
|
|
NPC
|
|
Sr.Secured Debt
|
|
BBB (low)*
|
|
BBB-*
|
|
Bal
|
|
BB+
|
|
NPC
|
|
Sr.Unsecured Debt
|
|
Not rated
|
|
BB
|
|
Not rated
|
|
B
|
|
|
|
|
|
*
|
|
Ratings are investment grade
|
In February 2007, DBRS, who had not previously issued ratings on the NPC, assigned new ratings
to NPC’s senior secured debt. The rating is BBB (low), which is the minimum level for investment
grade. DBRS’s trend for NPC is Stable.
In 2006, there were other changes to the ratings of NPC’s debt. Fitch upgraded the ratings
for NPC’s senior secured debt to BBB-, the minimum level for investment grade. The senior
unsecured debt for NPC was upgraded from BB- to BB, which is still non-investment grade. Fitch
revised the rating outlook for NPC from Positive to Stable. S&P upgraded the ratings of NPC’s
senior secured debt from BB to BB+, one level below investment grade. Moody’s re-affirmed its
ratings for NPC’s senior secured debt at Ba1, one level below investment grade.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings
are subject to revision and withdrawal at any time by the assigning rating organization, and each
rating should be evaluated independently of any other rating.
Energy Supplier Issues
With respect to NPC’s contracts for purchased power, NPC purchases and sell electricity with
counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract
that NPC is required to use as members of the WSPP. The WSPP contract is posted on the WSPP
website.
These contracts provide that a material adverse change may give rise to request adequate
financial assurance, which, if not provided within three business days, could cause a default. A
default must be declared within 30 days of the event, giving rise to the default becoming known. A
default will result in a termination payment equal to the present value of the net gains and losses
for the entire remaining term of all contracts between the parties aggregated to a single
liquidated amount due within three business days following the date the notice of termination is
received. The mark-to-market value, which is substantially based on quoted market prices, can be
used to roughly approximate the termination payment and benefit at any point in time. The net
mark-to-market value as of December 31, 2006 for all suppliers continuing to provide power under a
WSPP agreement would approximate a $55.8 million payment by NPC. These contracts qualify for the
normal purchases scope exception of SFAS No. 133, and as such, are not required to be marked to
market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to
Financial Statements for further discussion.
Gas Supplier Issues
With respect to the purchase and sale of natural gas, NPC uses several types of standard
industry contracts. The natural gas contract terms and conditions are more varied than the
electric contracts. Consequently, some of the contracts contain language similar to that found in
the WSPP agreement and other agreements have unique provisions dealing with material adverse
changes. Because of creditworthiness concerns, most contracts and confirmations for natural gas
purchases have been modified or separate agreements have been made to either shorten the normal
payment due date or require payment in advance of delivery. At the present time, four
counter-parties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service
contracts and Tariffs require the user establish and maintain creditworthiness to obtain service or
otherwise post cash or a letter of credit to be able to receive service. Service contracts are
subject to FERC approved tariffs, which, under certain circumstances, require the Utility to
provide collateral to continue receiving service. To date, a letter of credit has been provided to
one of NPC’s gas transporters.
Cross Default Provisions
None of the financing agreements of NPC contain a cross-default provision that would result in
an event of default by NPC upon an event of default by SPR or SPPC under any of its financing
agreements. In addition, certain financing agreements of NPC provide for an event of default if
there is a failure under other financing agreements of NPC to meet payment terms or to observe
other covenants that would result in an acceleration of payments due. Most of these default
provisions (other than ones relating to a failure to pay such other indebtedness when due) provide
for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may
rectify or correct the situation before it becomes an event of default.
71
SIERRA PACIFIC POWER COMPANY
RESULTS OF OPERATIONS
SPPC recognized net income of $57.7 million for the year ended December 31, 2006 compared to
net income of $52.1 million in 2005 and a net income of $18.6 million in 2004. SPPC’s operating
results for 2005 improved over 2004 primarily by the absence of the $47 million charge associated
with the Piñon Pine power plant project, consisting of an approximate $43 million disallowance and
a $4 million impairment charge. In January 2006, the Second Judicial District Court of the State
of Nevada vacated and remanded back to the PUCN for further review as to whether the costs
associated with the Piñon Pine power plant project were justly and reasonably incurred. The case
remains at the PUCN for review. See Note 13, Commitments and Contingencies for further discussion
of the case.
In 2006, SPPC paid $17.9 million in dividends to SPR and declared an additional $6.7 million
dividend. In January 2007, SPPC paid the $6.7 million dividend to SPR. In 2005, SPPC declared and
paid $23.9 million in common dividends to its parent SPR and declared and paid $3.9 million in
dividends to holders of its preferred stock.
Gross margin is presented by SPPC in order to provide information by segment that management
believes aids the reader in determining how profitable the electric and gas businesses are at the
most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in
accordance with SEC rules, provides a measure of income available to support the other operating
expenses of the business and is utilized by management in its analysis of its business.
SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s
regulatory treatment and its overall regulatory environment on a consistent basis. Gross
margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric
and natural gas supply costs versus the fixed rates collected from customers. While these
fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin
amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as
operating revenues less fuel and purchased power costs, provides a measure of income available to
support the other operating expenses of SPPC. Gross margin changes based on such factors as
general base rate adjustments (which are required to be filed by statute every two years) and
reflect SPPC’s strategy to increase internal power generation versus purchased power, which
generates no gross margin.
72
The components of gross margin for the years ended December 31 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
|
2006
|
|
|
Prior Year
|
|
|
2005
|
|
|
Prior Year
|
|
|
2004
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,020,162
|
|
|
|
5.5
|
%
|
|
$
|
967,427
|
|
|
|
9.7
|
%
|
|
$
|
881,908
|
|
|
Gas
|
|
|
210,068
|
|
|
|
17.8
|
%
|
|
|
178,270
|
|
|
|
15.9
|
%
|
|
|
153,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,230,230
|
|
|
|
7.4
|
%
|
|
$
|
1,145,697
|
|
|
|
10.6
|
%
|
|
$
|
1,035,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power
|
|
$
|
344,590
|
|
|
|
-2.1
|
%
|
|
$
|
352,098
|
|
|
|
15.5
|
%
|
|
$
|
304,955
|
|
|
Fuel for power generation
|
|
|
247,626
|
|
|
|
6.0
|
%
|
|
|
233,653
|
|
|
|
4.3
|
%
|
|
|
224,074
|
|
|
Gas purchased for resale
|
|
|
160,739
|
|
|
|
14.1
|
%
|
|
|
140,850
|
|
|
|
15.9
|
%
|
|
|
121,526
|
|
|
Deferral of energy
costs-electric-net
|
|
|
47,043
|
|
|
|
480.1
|
%
|
|
|
8,110
|
|
|
|
14.9
|
%
|
|
|
7,060
|
|
|
Deferral of energy costs-gas-net
|
|
|
6,947
|
|
|
|
-1027.5
|
%
|
|
|
(749
|
)
|
|
|
-81.9
|
%
|
|
|
(4,136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
806,945
|
|
|
|
9.9
|
%
|
|
$
|
733,962
|
|
|
|
12.3
|
%
|
|
$
|
653,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Costs by Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
639,259
|
|
|
|
7.6
|
%
|
|
$
|
593,861
|
|
|
|
10.8
|
%
|
|
$
|
536,089
|
|
|
Gas
|
|
|
167,686
|
|
|
|
19.7
|
%
|
|
|
140,101
|
|
|
|
19.3
|
%
|
|
|
117,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
806,945
|
|
|
|
9.9
|
%
|
|
$
|
733,962
|
|
|
|
12.3
|
%
|
|
$
|
653,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin by Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
380,903
|
|
|
|
2.0
|
%
|
|
$
|
373,566
|
|
|
|
8.0
|
%
|
|
$
|
345,819
|
|
|
Gas
|
|
|
42,382
|
|
|
|
11.0
|
%
|
|
|
38,169
|
|
|
|
5.0
|
%
|
|
|
36,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
423,285
|
|
|
|
2.8
|
%
|
|
$
|
411,735
|
|
|
|
7.7
|
%
|
|
$
|
382,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The causes for significant changes in specific lines comprising the results of operations
for the years ended are provided below (dollars in thousands except for amounts per unit):
Electric Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Electric Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
319,140
|
|
|
|
12.9
|
%
|
|
$
|
282,655
|
|
|
|
13.4
|
%
|
|
$
|
249,287
|
|
|
Commercial
|
|
|
370,617
|
|
|
|
13.9
|
%
|
|
|
325,456
|
|
|
|
10.3
|
%
|
|
|
294,956
|
|
|
Industrial
|
|
|
299,163
|
|
|
|
-10.3
|
%
|
|
|
333,621
|
|
|
|
12.8
|
%
|
|
|
295,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail revenues
|
|
|
988,920
|
|
|
|
5.0
|
%
|
|
|
941,732
|
|
|
|
12.1
|
%
|
|
|
840,125
|
|
|
Other
|
|
|
31,242
|
|
|
|
21.6
|
%
|
|
|
25,695
|
|
|
|
-38.5
|
%
|
|
|
41,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
1,020,162
|
|
|
|
5.5
|
%
|
|
$
|
967,427
|
|
|
|
9.7
|
%
|
|
$
|
881,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail sales in thousands
of megawatt-hours (MWh)
|
|
|
8,711
|
|
|
|
-5.7
|
%
|
|
|
9,234
|
|
|
|
1.0
|
%
|
|
|
9,143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average retail revenue per MWh
|
|
$
|
113.53
|
|
|
|
11.3
|
%
|
|
$
|
101.99
|
|
|
|
11.0
|
%
|
|
$
|
91.89
|
|
SPPC’s retail revenues increased in 2006 as compared to 2005 primarily due to increases
in retail rates and to a lesser extent customer growth. Retail rates increased as a result of
SPPC’s various BTER and deferred energy cases. (Refer to “Regulatory Proceedings”). The number of
residential, commercial and industrial customers increased (2.8%, 3.0% and 2.1% respectively).
These increases were offset by lower industrial energy revenues and MWh’s as a result of SPPC’s
large industrial customer, Barrick Gold, moving to distribution-only services effective December 1,
2005.
On December 1, 2006, SPPC filed its annual deferred energy filing and an application to
request recovery of deferred legal and settlement costs incurred for terminated power contracts
executed during the Western Energy Crisis. If approved by the PUCN,
73
the overall effect of both
filings would be a slight decrease in rates. SPPC requested that the rates become effective on
July 1, 2007. For further discussion on the various cases see Regulatory Proceedings, later.
SPPC’s retail revenues increased in 2005 as compared to 2004 due to increased rates and
customer growth. Customer rates for Nevada increased due to SPPC’s 2003 General Rate Case and
various deferred energy and BTER energy cases and an increase in California customer rates
effective December 1, 2004 and September 1, 2005. For further discussion of rate cases see Note 3,
Regulatory Actions of Notes to Financial Statements. Growth in residential and commercial
customers (3.1% and 3.5%, respectively) also contributed to the increase. Additionally,
contributing to the increase was the recognition in December 2005 of $12 million in DEAA revenues
as a result of Barrick’s transition to distribution only services effective December 1, 2005,
offset by lower BTER revenues.
The increase in Electric Operating Revenues — Other in 2006 compared to 2005, was primarily
due to the amortization of impact charges and increased wheeling revenues resulting from Barrick
becoming a distribution-only services customer.
The decrease in Electric Operating Revenues — Other in 2005 compared to 2004, was primarily
due to certain types of transactions that were reported in revenues for 2004 which are now being
netted in purchased power.
Gas Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Change
|
|
|
|
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
from Prior
|
|
|
|
|
|
|
from Prior
|
|
|
|
|
|
|
|
Amount
|
|
|
year
|
|
|
Amount
|
|
|
year
|
|
|
Amount
|
|
|
Gas Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
120,734
|
|
|
|
25.4
|
%
|
|
$
|
96,292
|
|
|
|
18.5
|
%
|
|
$
|
81,262
|
|
|
Commercial
|
|
|
54,316
|
|
|
|
22.6
|
%
|
|
|
44,286
|
|
|
|
13.5
|
%
|
|
|
39,019
|
|
|
Industrial
|
|
|
20,509
|
|
|
|
21.0
|
%
|
|
|
16,953
|
|
|
|
37.4
|
%
|
|
|
12,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail revenues
|
|
|
195,559
|
|
|
|
24.1
|
%
|
|
|
157,531
|
|
|
|
18.8
|
%
|
|
|
132,617
|
|
|
Wholesale
|
|
|
11,650
|
|
|
|
-34.5
|
%
|
|
|
17,786
|
|
|
|
-1.9
|
%
|
|
|
18,122
|
|
|
Miscellaneous
|
|
|
2,859
|
|
|
|
-3.2
|
%
|
|
|
2,953
|
|
|
|
-2.0
|
%
|
|
|
3,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
210,068
|
|
|
|
17.8
|
%
|
|
$
|
178,270
|
|
|
|
15.9
|
%
|
|
$
|
153,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail sales in thousands
of decatherms
|
|
|
15,058
|
|
|
|
1.6
|
%
|
|
|
14,819
|
|
|
|
6.6
|
%
|
|
|
13,896
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average retail revenues per decatherm
|
|
$
|
12.99
|
|
|
|
22.2
|
%
|
|
$
|
10.63
|
|
|
|
11.4
|
%
|
|
$
|
9.54
|
|
SPPC’s retail gas revenues increased in 2006 compared to 2005 primarily due to increases
in customer rates and customer growth. Retail rates increased as a result of SPPC’s various
general, energy and deferred energy rate cases (refer to “Regulatory Proceedings”). The number of
residential, commercial and industrial customers increased (4.3%,
3.7% and 16.7%, respectively).
SPPC’s retail gas revenues increased in 2005 compared to 2004 primarily due to increases in
Nevada customer rates, customer growth and weather. Customer rates increased as a result of SPPC’s
Purchased Gas Adjustment filings effective November 2004, and SPPC’s Gas Deferred Energy Rate case
and BTER Update effective November 2005 (refer to Note 3, Regulatory Actions of Notes to Financial
Statements). Customer growth increased as a result of an increase in the number of residential,
commercial, and industrial customers (4.3%, 3.5% and 15.9%, respectively). Weather contributed to
the increase in revenues with colder temperatures in the winter and spring, partially offset by
warmer temperatures in the fall.
The wholesale revenues for 2006 decreased compared to prior year 2005 primarily due to
decreased availability of gas for wholesale sales.
Wholesale and miscellaneous gas revenues for 2005 were consistent with the prior year.
74
Purchased Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Amount
|
|
Prior Year
|
|
Amount
|
|
Prior Year
|
|
Amount
|
|
Purchased Power
|
|
$
|
344,590
|
|
|
|
-2.1
|
%
|
|
$
|
352,098
|
|
|
|
15.5
|
%
|
|
$
|
304,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power in thousands
of MWh
|
|
|
5,334
|
|
|
|
-2.0
|
%
|
|
|
5,441
|
|
|
|
-4.9
|
%
|
|
|
5,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average cost per MWh of
Purchased power
|
|
$
|
64.60
|
|
|
|
-0.2
|
%
|
|
$
|
64.71
|
|
|
|
21.4
|
%
|
|
$
|
53.32
|
|
SPPC’s purchased power costs decreased in 2006 compared to 2005 primarily due to a
decrease in volume associated with the loss of Barrick, which transitioned to distribution only
services.
Purchased power costs increased in 2005 compared to 2004, due to higher prices. SPPC’s energy
contracts calculate prices using gas indexes; therefore, higher natural gas prices in 2005
increased the price of purchased power. Overall volumes for 2005 were lower than 2004 due to
certain types of transactions that were reported in revenues for 2004 which are now being netted in
purchased power and because purchases associated with risk management activities, which are
included in purchased power, decreased in 2005.
Fuel for Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Fuel for Power Generation
|
|
$
|
247,626
|
|
|
|
6.0
|
%
|
|
$
|
233,653
|
|
|
|
4.3
|
%
|
|
$
|
224,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thousands of MWh generated
|
|
|
4,059
|
|
|
|
-7.3
|
%
|
|
|
4,379
|
|
|
|
-4.9
|
%
|
|
|
4,605
|
|
|
Average fuel cost per MWh
of Generated Power
|
|
$
|
61.01
|
|
|
|
14.3
|
%
|
|
$
|
53.36
|
|
|
|
9.7
|
%
|
|
$
|
48.66
|
|
Fuel for power generation and the average fuel cost per MWh increased in
2006 compared to 2005. The increase is primarily due to hedging instruments which were purchased
during the period when gas prices were escalating as a result of the 2005 hurricanes in the
southern United States. The settlement of these instruments negatively impacted the average cost
per MWH as natural gas prices were decreasing in 2006. The settlements of hedging instruments in
the fourth quarter of 2005 partially offset the gas cost in 2005. MWh generated decreased as
compared to 2005 primarily due to Barrick, which transitioned to distribution-only service in 2006.
Fuel for power generation costs increased in 2005 as compared to 2004 due to increases in
natural gas and coal prices. However, the natural gas cost increases were partially offset by
SPPC’s hedging strategies, as discussed in Energy Supply (Utilities). The decrease in the volume of
generation was primarily due to SPPC relying more on purchased power to satisfy its native load
requirements.
Gas Purchased for Resale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Gas Purchased for Resale
|
|
$
|
160,739
|
|
|
|
14.1
|
%
|
|
$
|
140,850
|
|
|
|
15.9
|
%
|
|
$
|
121,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Purchased for Resale
(in thousands of decatherms)
|
|
|
17,491
|
|
|
|
5.4
|
%
|
|
|
16,592
|
|
|
|
-6.1
|
%
|
|
|
17,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Cost per decatherm
|
|
$
|
9.19
|
|
|
|
8.2
|
%
|
|
$
|
8.49
|
|
|
|
23.4
|
%
|
|
$
|
6.88
|
|
The cost of gas purchased for resale and average cost per decatherm increased in 2006 as
compared to 2005. The increase is primarily due to hedging instruments which were purchased during
the period when gas prices were escalating as a result of the 2005 hurricanes in the southern
United States. The settlement of these instruments negatively impacted the average cost per
decatherm as
75
natural gas prices were decreasing in 2006. The volume of gas purchased for resale
increased primarily due to the colder winter weather during the fourth quarter of 2006.
The cost of gas purchased for resale increased in 2005 as compared to 2004 due to increases in
natural gas prices. The volume of gas purchased for resale decreased during this period due to the
fuel forecast more closely matching usage, leaving less fuel available for wholesale sales. This
decrease in volume of gas was partially offset by the increase in demand for gas for resale during
the first two quarters of 2005 due to colder winter weather.
Deferral of Energy Costs — Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Deferred energy costs — electric — net
|
|
$
|
47,043
|
|
|
|
N/A
|
|
|
$
|
8,110
|
|
|
|
14.9
|
%
|
|
$
|
7,060
|
|
|
Deferred energy costs — gas — net
|
|
|
6,947
|
|
|
|
N/A
|
|
|
|
(749
|
)
|
|
|
-81.9
|
%
|
|
|
(4,136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
53,990
|
|
|
|
|
|
|
$
|
7,361
|
|
|
|
|
|
|
$
|
2,924
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
energy — costs — net represents the difference between actual fuel and purchased
power costs incurred during the period and amounts recoverable through current rates. To the
extent actual costs exceed amounts recoverable through current rates the excess is recognized as a
reduction in costs. Conversely to the extent actual costs are less than amounts recoverable
through current rates the difference is recognized as an increase in costs. Deferred energy costs
- net also includes the current amortization of fuel and purchased power costs previously deferred.
Deferred energy costs — electric — net for 2006, 2005 and 2004 reflect amortization of
deferred energy costs of $46.3 million, $56.7 million and $37.0 million, respectively; and an
over-collection of amounts recoverable in rates of $0.7 million in 2006 and an under-collection of
$48.6 million and $29.9 million in 2005 and 2004, respectively. See Note 1, Summary of
Significant Accounting Policies, Deferral of Energy Costs of Notes to Financial Statements for
further detail of deferred energy balances.
Deferred energy costs — gas — net for 2006, 2005 and 2004 reflect amortization of deferred
energy costs of $6.3 million, $1.5 million and $3.3 million, respectively; and an over-collection
of amounts recoverable in rates of $0.6 million in 2006 and an under-collection in 2005 and 2004 of
$2.3 million and $7.4 million, respectively.
Allowance for Funds Used During Construction (AFUDC)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Prior year
|
|
|
Amount
|
|
|
Allowance for other funds used
during construction
|
|
$
|
6,471
|
|
|
|
294.8
|
%
|
|
$
|
1,639
|
|
|
|
-4.6
|
%
|
|
$
|
1,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for borrowed funds used
during construction
|
|
|
5,505
|
|
|
|
266.0
|
%
|
|
|
1,504
|
|
|
|
-47.2
|
%
|
|
|
2,849
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,976
|
|
|
|
281.0
|
%
|
|
$
|
3,143
|
|
|
|
-31.2
|
%
|
|
$
|
4,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AFUDC for SPPC is higher in 2006 compared to 2005 due to an increase in the average
Construction Work-In-Progress (CWIP) balance on which AFUDC is calculated due to the expansion of
the Tracy Generating Station which started in late 2005.
AFUDC is lower in 2005 compared to 2004 due to a decrease in the average CWIP balance, primary
as a result from the completion in May 2004 of the 3 year Falcon-Gonder 345KV Transmission Line
project.
76
Other (Income) and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Change from
|
|
|
|
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Prior year
|
|
Amount
|
|
Other operating expense
|
|
$
|
141,350
|
|
|
|
7.2
|
%
|
|
$
|
131,901
|
|
|
|
3.0
|
%
|
|
$
|
128,091
|
|
|
Maintenance expense
|
|
$
|
31,273
|
|
|
|
17.2
|
%
|
|
$
|
26,690
|
|
|
|
22.0
|
%
|
|
$
|
21,877
|
|
|
Depreciation and amortization
|
|
$
|
87,279
|
|
|
|
-3.6
|
%
|
|
$
|
90,569
|
|
|
|
4.3
|
%
|
|
$
|
86,806
|
|
|
Interest charges on long-term debt
|
|
$
|
71,869
|
|
|
|
3.8
|
%
|
|
$
|
69,240
|
|
|
|
-2.9
|
%
|
|
$
|
71,312
|
|
|
Interest for energy suppliers
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
(2,396
|
)
|
|
|
-78.2
|
%
|
|
$
|
(10,999
|
)
|
|
Interest charges-other
|
|
$
|
5,142
|
|
|
|
38.0
|
%
|
|
$
|
3,727
|
|
|
|
-30.6
|
%
|
|
$
|
5,367
|
|
|
Interest accrued on deferred energy
|
|
$
|
(5,996
|
)
|
|
|
-15.5
|
%
|
|
$
|
(7,092
|
)
|
|
|
38.2
|
%
|
|
$
|
(5,133
|
)
|
|
Other income
|
|
$
|
(9,412
|
)
|
|
|
58.5
|
%
|
|
$
|
(5,940
|
)
|
|
|
74.4
|
%
|
|
$
|
(3,406
|
)
|
|
Disallowed merger costs
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
1,929
|
|
|
Plant costs disallowed
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
47,092
|
|
|
Other expense
|
|
$
|
8,422
|
|
|
|
12.4
|
%
|
|
$
|
7,493
|
|
|
|
30.9
|
%
|
|
$
|
5,726
|
|
Other operating expense increased for 2006 compared to 2005 due to increased amortization
of regulatory assets resulting from SPPC’s GRC, as discussed in Regulatory Proceedings. Also
contributing to the increase was the recovery in 2005 of a claim against Pacific Gas and Electric;
partially offset by Enron legal fees incurred in 2005.
Other operating expense increased for 2005 compared to 2004 primarily due to severance costs
associated with the reorganization of SPPC, NPC and SPR.
The increase in Maintenance expense for 2006 compared to 2005 is primarily due to higher costs
for scheduled maintenance and forced outages in 2006 at Ft. Churchill and Valmy; partially offset
by a 2006 planned major outage at Tracy that was rescheduled to 2007.
The increase in Maintenance expense for 2005 compared to 2004 is primarily due to the timing
of scheduled and unscheduled plant maintenance at Valmy.
Depreciation and amortization were lower in 2006 than 2005 due to the change in depreciation
rates as ordered by PUCN in SPPC’s General Electric and Gas Rate Case. For further information on
SPPC’s General and Electric Rate Case see Regulatory Proceedings, later.
Depreciation and amortization were higher in 2005 than 2004 due to an increase in
plant-in-service from regular system growth.
SPPC’s interest charges on Long-Term Debt for the year ended December 31, 2006 increased from
2005 due primarily to interest on the $300 million Series M Notes issued in March 2006, partially
offset by debt redemptions in 2006 of $188 million, and the refinancing of $268 million of tax
exempt debt from fixed rate to variable in November 2006. SPPC’s interest charges on Long-Term Debt
for the year ended December 31, 2005 decreased from 2004 as a result of the reduction in interest
rate during 2004 associated with the replacement of its 10.5% $100 million term loan facility with
6.25% $100 million Series H Notes, and a reduction in interest rate in April 2004, of SPPC’s $80
million Washoe Water Bonds from 7.5% to 5.0%. See Note 6, Long-Term Debt of the Notes to Financial
Statements for additional information regarding long-term debt.
SPPC’s interest charges for energy suppliers for the year ended December 31, 2005 reflects the
reversal of interest of $3.2 million resulting from the November 2005 settlement agreement between
the Utilities and Enron. SPPC’s Interest charges for energy suppliers for the year ended December
31, 2004 reflects the reversal of interest of $12.3 million resulting from a December 2004 ruling
by the U.S. District Court that lowered the interest rate previously accrued. See Note 13,
Commitments and Contingencies, of the Notes to Financial Statements, for more information regarding
the Enron litigation.
SPPC’s interest charges-other for the year ended December 31, 2006 increased compared to the
same period in 2005 primarily due to higher amortization of debt issuance costs related to new debt
issuances. See Financing Transactions. SPPC’s Interest charges-other for the year ended
December 31, 2005 decreased compared to the same period in 2004 due primarily to the absence of
charges related to the accounts receivable facility and short-term debt.
SPPC’s interest accrued on deferred energy costs for the year ended December 31, 2006, was
lower than the same period in 2005 due primarily to lower deferred
energy balances during 2006, when
compared to the same period in 2005. Interest accrued on deferred energy costs for the year ended
December 31, 2005, was higher than the same period in 2004 due to higher deferred fuel and
77
purchased power balances and carrying charge rates during 2005. See Note 3, Regulatory Actions of
the Notes to Financial Statements for further discussion of deferred
energy accounting issues.
SPPC’s other income increased for the year ended December 31, 2006, compared to the same
period in 2005 primarily due to an increase in interest income associated with higher cash balances
from the issuance of new debt in March 2006, as well as gains from the sale of property. SPPC’s
other income increased for the year ended December 31, 2005, compared to the same period in 2004
due primarily to an increase in interest income.
Disallowed merger costs expense includes the 2004 write-off of costs that resulted from the
July 1999 merger between SPR and NPC, allocable to non-Nevada jurisdictional electricity sales,
which were determined not to be recoverable in future rates.
SPPC’s plant costs disallowed is the result of the decision by the PUCN to disallow recovery
of a portion of the costs associated with the Piñon Pine power plant project. See Note 3,
Regulatory Actions and Note 13, Commitments and Contingencies of the Notes to Financial Statements,
for details.
SPPC’s other expense for the year ended December 31, 2006 increased from the same period in
2005, due primarily to a loss on the disposition of property, higher donations, assistance program
expenses, and penalties. SPPC’s other expense for the year ended December 31, 2005 increased from
the same period in 2004. Higher expense was recognized during 2005 related to SPPC’s California
Restructure Implementation costs of approximately $1 million that were disallowed by the CPUC.
ANALYSIS OF CASH FLOWS
SPPC’s cash flows decreased slightly during the year ended December 31, 2006, when compared to
the same period in 2005, as a result of an increase in cash used by investing activities offset by
an increase in cash from operating and financing activities.
Cash used by investing activities increased primarily as a result of the expansion of the
Tracy plant during the year ended December 31, 2006, compared to the same period in 2005.
At various times during the year ended December 31, 2006, SPPC borrowed approximately $248
million under its revolving credit facility, all of which was repaid during 2006. SPPC also issued
$300 million in 6.0% General and Refunding Mortgage Notes, Series M and $268 million in variable
interest Pollution Control Revenue Bonds. A portion of the draw on the credit line was used to
retire approximately $198 million of SPPC’s Medium Term Notes Series A, B and C. The net proceeds
of the $300 million offering were used to pay off amounts borrowed under the revolving credit
facility, redeem $20 million of Medium Term Notes, Series C, redeem $50 million of preferred stock and pay associated costs, premiums and dividends.
Proceeds from Pollution Control Bonds and cash from
operations were used to retire $269 million of SPPC’s
existing tax-exempt bonds. In
2006, SPPC paid dividends to SPR of approximately $17.9 million and received a capital contribution
of $75 million from SPR.
Cash from operating activities were higher in 2006 mainly due to the settlement of balances
outstanding for tax sharing agreements, a reduction in prepayments for energy and increases in
general and energy rates, offset by the settlement with Enron during the first quarter.
SPPC’s cash flows increased during the year ended December 31, 2005, when compared to the same
period in 2004, as a result of an increase in cash flows from operating activities partially offset
by increases in cash used in investing and financing activities. Cash flows from operating
activities were higher in 2005 due to rate increases that became effective in the second quarter of
2004, which was the result of SPPC’s General and Deferred Rate Cases (refer to “Regulatory
Proceedings”). Also causing an increase in cash flow from operations was the $11 million escrow
payment for Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the
establishment of the revolving credit facility and changes in accounts receivables for tax sharing
agreements, offset by energy costs being higher than amounts recovered in rates in 2005. Cash
flows used in investing activities increased primarily as a result of construction activity related
to growth. Cash used for financing activities increased due to payment of dividends to the parent
in 2005, offset by the payoff of the short-term credit facility in 2004.
78
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
SPPC’s primary source of operating cash flows are electric and gas revenues, including the
recovery of previously deferred energy and gas costs. Significant uses of cash flows from
operations include the purchase of electricity and natural gas, other operating expenses and the
payment of interest on SPPC’s outstanding indebtedness.
|
|
|
|
|
|
|
Available Liquidity as of December 31, 2006 (in millions)
|
|
|
|
|
SPPC
|
|
|
Cash and Cash Equivalents
|
|
$
|
53.3
|
|
|
Balance available on Revolving Credit Facility
|
|
|
340.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Available Liquidity
1
|
|
$
|
393.9
|
|
|
|
|
|
|
|
|
|
|
1
|
As of February 23, 2007, SPPC had approximately $331.1
million available under its revolving credit facility. Additionally,
if necessary, SPPC has the ability to issue additional debt, as
discussed under Limitations on Indebtedness.
|
In December 2006, SPR contributed capital to SPPC of approximately $75 million. SPPC used
the proceeds to repay indebtedness under its revolving credit facility, and for general corporate
purposes. There were no other capital contributions from SPR to SPPC in 2006.
In 2006, SPPC had paid $17.9 million in dividends to SPR and declared an additional $6.7
million dividend. In January 2007, SPPC paid the $6.7 million dividend to SPR.
SPPC anticipates that it will be able to meet operating costs, such as fuel and purchased
power costs, with internally generated funds, including the recovery of deferred energy. However,
to fund capital requirements, SPPC may be required to meet such financial obligations with a
combination of internally generated funds, the use of its revolving credit facility, and if
necessary, the issuance of long-term debt and/or capital contribution from SPR.
SPPC’s overall liquidity continued to improve in 2006. The revolving credit facility was
increased to $350 million in April, 2006, providing $100 million of additional liquidity for
increased commodity prices. SPPC’s debt profile improved as a result of refinancing more than $536
million of long-term debt. These refinancings are expected to reduce future interest expense.
SPPC designs operating and capital budgets to control operating costs and capital
expenditures. In addition to operating expenses, SPPC has continuing commitments for capital
expenditures for construction, improvement and maintenance of facilities.
Detailed below are SPPC’s Capital Structure, Capital Requirements, Contractual Obligations,
recently completed Financing Transactions and Factors Affecting Liquidity including SPPC’s ability
to obtain debt on favorable terms and limitations on indebtedness.
Capital Structure
SPPC’s actual consolidated capital structure was as follows at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
Current Maturities of Long-Term Debt
|
|
$
|
2,400
|
|
|
|
0.1
|
%
|
|
$
|
52,400
|
|
|
|
3.00
|
%
|
|
Long-Term Debt
|
|
|
1,070,858
|
|
|
|
54.7
|
%
|
|
|
941,804
|
|
|
|
53.1
|
%
|
|
Preferred Stock
|
|
|
—
|
|
|
|
|
|
|
|
50,000
|
|
|
|
2.8
|
%
|
|
Common Equity
|
|
|
884,737
|
|
|
|
45.2
|
%
|
|
|
727,777
|
|
|
|
41.1
|
%
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,957,995
|
|
|
|
100.0
|
%
|
|
$
|
1,771,981
|
|
|
|
100
|
%
|
|
|
|
|
|
|
Capital Requirements
Construction Expenditures
SPPC’s cash construction expenditures are expected to increase due to programs designed to
meet electric load growth and reliability needs. Cash construction expenditures for the years
ended 2006, 2005 and 2004 were approximately $285 million, $113 million and $104 million,
respectively. SPPC’s cash construction expenditures for 2007 are projected to be $432.8 million.
SPPC’s cash construction expenditures for 2007 through 2011 are projected to be $1.9 billion. To
fund these capital projects SPPC may meet such financial obligations with a combination of
internally generated funds, the use of its revolving credit facility and if necessary, the
79
issuance
of long-term debt and/or capital contributions from SPR. Depending on the progress of the Ely
Energy Center the timing and extent of the estimated capital expenditures necessary may change.
Contractual Obligations
The table below provides SPPC’s consolidated contractual obligations, not including estimated
construction expenditures described above, as of December 31, 2006, that SPPC expects to satisfy
through a combination of internally generated cash and, as necessary, through the issuance of
short-term and long-term debt (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment Due by Period
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Thereafter
|
|
|
Total
|
|
|
Long-Term Debt Maturities
|
|
$
|
2,400
|
|
|
$
|
322,400
|
|
|
$
|
80,600
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
668,250
|
|
|
$
|
1,073,650
|
|
|
Long-Term Debt Interest
Payments
|
|
|
61,979
|
|
|
|
49,235
|
|
|
|
38,386
|
|
|
|
38,377
|
|
|
|
38,377
|
|
|
|
402,091
|
|
|
|
628,445
|
|
|
Purchased Power
|
|
|
163,165
|
|
|
|
125,161
|
|
|
|
98,028
|
|
|
|
93,836
|
|
|
|
95,231
|
|
|
|
1,308,566
|
|
|
|
1,883,987
|
|
|
Coal and Natural Gas
|
|
|
201,068
|
|
|
|
85,018
|
|
|
|
73,392
|
|
|
|
48,418
|
|
|
|
48,418
|
|
|
|
361,358
|
|
|
|
817,672
|
|
|
Capital Purchase Agreements
|
|
|
13,121
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
13,121
|
|
|
Operating Leases
|
|
|
10,635
|
|
|
|
10,297
|
|
|
|
8,931
|
|
|
|
7,587
|
|
|
|
778
|
|
|
|
36,587
|
|
|
|
74,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Cash
Obligations
|
|
$
|
452,368
|
|
|
$
|
592,111
|
|
|
$
|
299,337
|
|
|
$
|
188,218
|
|
|
$
|
182,804
|
|
|
$
|
2,776,852
|
|
|
$
|
4,491,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan Matters
SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC.
The annual net benefit cost for the plan is expected to decrease in 2007 by approximately $1.3
million compared to the 2006 cost of $30.6 million. As of September 30, 2006, the measurement date,
the plan was fully funded on a FAS 87 ABO basis (fair value of assets exceeded ABO). During 2006,
SPR contributed a total of $16 million to meet its funding obligations under the plan. At the
present time it is not expected that any additional funding will be required in 2007 to meet the
minimum funding level requirements defined by the Pension Benefit Guaranty Corporation and ERISA.
However, SPR and the Utilities currently expect to contribute an amount similar to the 2006
funding. The amounts to be contributed may change subject to market conditions.
Financing Transactions (SPPC)
Pollution Control and Gas and Water Facilities Refunding Revenue Bonds, Series 2006, 2006A, 2006B and 2006C
In November 2006, on behalf of SPPC, Humboldt County, Nevada (Humboldt County) issued $49.75
million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006,
due October 2029. On the same date, on behalf of SPPC, Washoe County, Nevada (Washoe County)
issued $58.7 million aggregate principal amount of it Gas Facilities Refunding Revenue Bonds,
Series 2006A, due August 2031; $75 million aggregate principal amount of its Water Facilities
Refunding Revenue Bonds, Series 2006B, due March 2036; and $84.8 million aggregate principal amount
of its Gas and Water Facilities Refunding Revenue Bonds, Series 2006C, due March 2036.
In connection with the issuance of these Bonds, SPPC entered into financing agreements with
Humboldt County and Washoe County, pursuant to which Humboldt County and Washoe County loaned the
proceeds from the sales of the bonds to SPPC. SPPC’s payment obligations under the financing
agreements are secured by SPPC’s General and Refunding Mortgage Notes, Series N.
80
The interest rates of the Bonds were initially determined by an auction. The method of
determining the interest rate on the Bonds may be converted from time to time so that such Bonds
would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.
The proceeds of the offerings were used to refund the following, all of which were previously
issued for the benefit of SPPC:
|
|
•
|
|
$17.5 million principal amount of 6.65% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1987
|
|
|
|
|
•
|
|
$20 million principal amount of 6.55% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1990
|
|
|
|
|
•
|
|
$21.2 million principal amount of 6.70% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1992
|
|
|
|
|
•
|
|
$75 million principal amount of 6.65% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1987
|
|
|
|
|
•
|
|
$45 million principal amount of 6.30% Washoe County’s Gas and Water Facilities
Refunding Revenue Bonds, Series 1987
|
|
|
|
|
•
|
|
$30 million principal amount of 5.90% Washoe County’s Gas and Water Facilities
Refunding Revenue Bonds, Series 1993B
|
|
|
|
|
•
|
|
$9.8 million principal amount of 5.90% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1993A
|
|
|
|
|
•
|
|
$39.5 million principal amount of 6.55% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1987
|
|
|
|
|
•
|
|
$10.25 million principal amount of 6.30% Humboldt County’s Pollution Control Refunding
Revenue Bonds, Series 1992A
|
Humboldt County Pollution Control Refunding Revenue Bonds
In October 2006, the 6.35% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series
1992B, due August 2022, in the amount of $1 million were redeemed at 100% of the stated principal
amount, plus accrued interest.
Revolving Credit Facility
In April 2006, SPPC increased the size of its amended and restated revolving credit facility
expiring 2010 to $350 million. The facility will provide additional liquidity for increased
commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2006,
SPPC had $9.4 million of letters of credit outstanding and had no amounts borrowed under the
revolving credit facility. As of February 23, 2007, SPPC had
$18.9 million of letters of credit
and had no amounts borrowed under the revolving credit facility.
The SPPC Credit Agreement contains two financial maintenance covenants. The first requires
that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of
the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC
maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the
last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less
than 2.0 to 1. As of December 31, 2006, SPPC was in compliance with these covenants.
The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC’s
other financing agreements to meet certain payment terms or to observe other covenants that would
result in an acceleration of payments due.
The SPPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends.
These limitations are discussed in Note 8, Debt Covenant and Other Restrictions.
General and Refunding Mortgage Notes, Series M
In March 2006, SPPC issued and sold $300 million of its 6.00% General and Refunding Mortgage
Notes, Series M, due May 15, 2016. The Series M Notes were issued with registration rights.
Proceeds of the offering were used to repay $173 million borrowed under the revolving credit
facility which was utilized to:
|
|
•
|
|
fund the early redemption of $110 million aggregate principal amount of SPPC’s
Collateralized Medium Term 6.95% to 8.61% Series A Notes due 2022;
|
|
|
|
|
•
|
|
fund the early redemption of $58 million aggregate principal amount of SPPC’s
Collateralized Medium Term 7.10% to 7.14% Series B Notes due 2023;
|
|
|
|
|
•
|
|
pay for maturing debt of $30 million aggregate principal amount of SPPC’s Collateralized
Medium Term 6.81% to 6.83% Series C Notes due 2006; and
|
|
|
|
|
•
|
|
pay for $51 million in connection with the redemption of $50 million of SPPC’s Series A
Preferred Stock (two million shares of stock were redeemed at a redemption price per share
of $25.683, plus accrued dividends to the redemption date of $.4875 per share).
|
|
|
|
|
•
|
|
pay for maturing debt of $20 million aggregate principal amount of SPPC’s Collateralized
Medium Term 6.62% to 6.65% Series C Notes due 2006.
|
81
Discharge of SPPC’s First Mortgage Indenture
In November 2006, following the refunding of the $268.25 million aggregate principal amount of
Pollution Control and Gas & Water Refunding Revenue Bonds (see Financing Transactions above), the
first mortgage bonds which secured these revenue bonds were retired.
In November 2006, the remaining $20 million aggregate principal amount of Series C Medium
Terms Notes matured. On that date, the first mortgage bonds which secured the Medium Term Notes
were retired.
With the conclusion of these two transactions, all of the bonds outstanding under the First
Mortgage Indenture were retired as of November 2006, and all filings necessary to make effective
the release of the lien of the First Mortgage Indenture were completed as of January 2007. Upon
the satisfaction and discharge of the First Mortgage Indenture, SPPC’s General and Refunding
Mortgage Indenture, dated as of May 2001, with the Bank of New York as Trustee, became the first
priority lien on substantially all of SPPC’s utility property in Nevada and California.
Factors Affecting Liquidity
Limitations on Indebtedness
Certain factors impact SPPC’s ability to issue debt:
|
|
1.
|
|
Financing Authority from the PUCN. In February 2006, SPPC received PUCN
authorization to enter into financings of $1.36 billion which amount includes $350
million for the revolving credit facility (described above). SPPC has issued $21
million of the new debt authorized in the PUCN Order. SPPC’s remaining authority under
this PUCN Order allows SPPC to use its $350 million revolving credit facility, to issue
$349 million in new debt, and to refinance existing debt as specified in the order.
|
|
|
|
|
2.
|
|
Limits on Bondable Property. To the extent that SPPC has the ability to issue
debt under the most restrictive covenants in its financing agreements and has financing
authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited
by the amount of bondable property or retired bonds that can be used to issue debt under
the General and Refunding Mortgage Indenture. As of December 31, 2006, SPPC has the
capacity to issue $381 million of General and Refunding Mortgage Securities.
|
|
|
|
|
3.
|
|
Financial Covenants in its and SPR’s financing agreements. The terms of certain
SPR debt further prohibit SPPC and NPC from incurring additional indebtedness unless
certain conditions have been met. See SPR’s Limitations on Indebtedness for details of
these restrictions. In addition to the SPR debt, the terms of SPPC’s Series H Notes and
SPPC’s Amended and Restated Revolving Credit Agreement restrict SPPC from issuing
additional indebtedness unless certain covenants are satisfied. See Note 8, Debt
Covenant and Other Restrictions.
|
As of December 31, 2006, the financial covenants under SPPC’s revolving credit
facility, which are more restrictive than the Series H Notes restriction, would allow SPPC
to issue up to $797 million of additional debt. The covenant limitations of certain SPR
debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and
NPC, at $2.1 billion as of December 31, 2006.
Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s
debt covenant limitations may allow for higher or lower borrowings than $2.1 billion,
depending on the Utilities’ combined usage of their revolving credit facilities at the
time of the covenant calculation.
Limitations on Ability to Issue General and Refunding Mortgage Bonds
SPPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC’s
properties in Nevada and California. As of December 31, 2006, $1.4 billion of SPPC’s General and
Refunding Mortgage Securities were outstanding. As mentioned in (2) above under “
Limitations on
Indebtedness
” additional securities may be issued under the General and Refunding Mortgage
Indenture as of December 31, 2006. That amount has been determined on the basis of:
|
|
1.
|
|
70% of net utility property additions;
|
|
|
|
|
2.
|
|
the principal amount of retired General and Refunding Mortgage Securities; and/or
|
|
|
|
|
3.
|
|
the principal amount of first mortgage bonds retired after October 2001.
|
82
SPPC also has the ability to release property from the lien of the General and Refunding
Mortgage Indenture on the basis of net property additions, cash and/or retired bonds. To the extent
SPPC releases property from the lien of its General and Refunding Mortgage Indenture, it will
reduce the amount of securities issuable under that indenture.
Credit Ratings
SPPC is rated by four Nationally Recognized Statistical Rating Organizations S&P, Moody’s,
Fitch, and DBRS. As of February 23, 2007, the ratings are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rating Agency
|
|
|
|
|
|
DBRS
|
|
Fitch
|
|
Moody’s
|
|
S&P
|
|
SPPC
|
|
Sr.Secured Debt
|
|
BBB (low)*
|
|
BBB-*
|
|
Ba1
|
|
BB+
|
|
|
|
|
|
*
|
|
Ratings are investment grade
|
In February 2007, DBRS, who had not previously issued ratings on SPPC, assigned new ratings to
SPPC’s senior secured debt. The rating is BBB (low), which is the minimum level for investment
grade. DBRS’s trend for SPPC is Stable.
In 2006, there were other changes to the ratings of SPPC’s debt. Fitch upgraded the ratings
for SPPC’s senior secured debt to BBB-, the minimum level for investment grade, and revised the
rating outlook for SPPC from Positive to Stable. S&P upgraded the ratings of SPPC’s senior secured
debt from BB to BB+, one level below investment grade. Moody’s re-affirmed its ratings for SPPC’s
senior secured debt at Ba1, one level below investment grade.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings
are subject to revision and withdrawal at any time by the assigning rating organization, and each
rating should be evaluated independently of any other rating.
Energy Supplier Issues
With respect to SPPC’s contracts for purchased power, SPPC purchases and sell electricity with
counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract
that SPPC is required to use as members of the WSPP. The WSPP contract is posted on the WSPP
website.
These contracts provide that a material adverse change may give rise to request adequate
financial assurance, which, if not provided within three business days, could cause a default. A
default must be declared within 30 days of the event, giving rise to the default becoming known. A
default will result in a termination payment equal to the present value of the net gains and losses
for the entire remaining term of all contracts between the parties aggregated to a single
liquidated amount due within three business days following the date the notice of termination is
received. The mark-to-market value, which is substantially based on quoted market prices, can be
used to roughly approximate the termination payment and benefit at any point in time. The net
mark-to-market value as of December 31, 2006 for all suppliers continuing to provide power under a
WSPP agreement would approximate a $44.5 million payment by SPPC. These contracts qualify for the
normal purchases scope exception of SFAS No. 133, and as such, are not required to be marked to
market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to
Financial Statements for further discussion.
Gas Supplier Issues
With respect to the purchase and sale of natural gas, SPPC uses several types of standard
industry contracts. The natural gas contract terms and conditions are more varied than the
electric contracts. Consequently, some of the contracts contain language similar to that found in
the WSPP agreement and other agreements have unique provisions dealing with material adverse
changes. Because of creditworthiness concerns, most contracts and confirmations for natural gas
purchases have been modified or separate agreements have been made to either shorten the normal
payment due date or require payment in advance of delivery. At the present time, four
counter-parties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service
contracts and Tariffs require the user establish and maintain creditworthiness to obtain service or
otherwise post cash or a letter of credit to be able to receive service. Service contracts are
subject to FERC approved tariffs, which, under certain circumstances, require the Utility to
provide collateral to continue receiving service.
Cross Default Provisions
SPPC’s financing agreements do not contain any cross-default provisions that would result in
an event of default by SPPC upon an event of default by SPR or NPC under any of their respective
financing agreements. Certain financing agreements of SPPC provide for an event of default if
there is a failure under other financing agreements of SPPC to meet payment terms or to observe
83
other covenants that would result in an acceleration of payments due. Most of these default
provisions (other than ones relating to a failure to pay such other indebtedness when due) provide
for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may
rectify or correct the situation before it becomes an event of default.
REGULATORY PROCEEDINGS (UTILITIES)
SPR is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005).
As a result, SPR and all of its subsidiaries (whether or not engaged in any energy related
business) are required to maintain their books and records in accordance with Federal Energy
Regulatory Commission (“FERC”) regulations and to make them available to the FERC, the Public
Utilities Commission of Nevada (“PUCN”) and California Public Utility Commission (“CPUC”). In
addition, the PUCN, CPUC, and the FERC have the authority to review the allocation of costs of
non-power goods and administrative services among SPR and its subsidiaries. The FERC has the
general authority to require that rates subject to its jurisdiction be just and reasonable and in
this context would continue to be able to, among other things, review transactions between SPR, NPC
and/or SPPC and/or any other affiliated company. SPR does not expect that the new PUHCA law or the
regulations promulgated by the FERC will have a material impact on the company and how its public
utility subsidiaries are regulated.
The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC,
with respect to rates, standards of service, siting of and necessity for generation and certain
transmission facilities, accounting, issuance of securities and other matters with respect to
electric distribution and transmission operations. NPC and SPPC submit Integrated Resource Plans
(“IRPs”) to the PUCN for approval.
Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily
by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service,
interconnection, accounting and other matters in connection with the Utilities’ sale of electricity
for resale and interstate transmission. The FERC also has jurisdiction over the natural gas
pipeline companies from which the Utilities take service.
As a result of regulation, many of the fundamental business decisions of the Utilities, as
well as the rate of return they are permitted to earn on their utility assets, are subject to the
approval of the governmental commissions. The following regulatory proceedings have affected, or
are expected to affect the utilities financial positions, results of operations and cash flows.
The Utilities are required to file annual periodic Deferred Energy Accounting Adjustment
(DEAA) cases, annual Base Tariff Energy Rate (BTER) Updates and biennial General Rate Cases (GRCs)
in Nevada. A DEAA case is filed to recover/refund any over/under collection of prior energy costs
and the BTER update is to set rates to recover current energy costs. A GRC filing is to set rates
to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested
capital. As of December 31, 2006, NPC’s and SPPC’s balance sheet included approximately $488.9
million and $61.6 million, respectively, of deferred energy costs of which approximately $334.8
million and $33.7 million have been previously approved for collection over various periods. The
remaining amounts will be requested in future regulatory filings. Refer to Note 1, Summary of
Significant Accounting Policies, of the Notes to Financial Statements.
The following summarizes pending and approved rate case applications filed in 2005, 2006 and
2007. Each of these rate cases, as well as other regulatory matters such as, the Utilities’
Integrated Resource Plans and subsequent amendments, other Nevada matters, California matters and
FERC matters, are discussed in more detail within this section.
Pending Rate Cases
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NPC 2007 Deferred Energy Rate Case and BTER Update
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Application to create a new DEAA rate and to update the going forward BTER. In this
application, NPC requests to decrease rates by $33.2 million, a decrease of 1.6% while
recovering $75 million of deferred fuel and purchased power costs. NPC has requested the
amortization to begin June 1, 2007 and to continue for a fourteen month period.
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NPC 2007 Western Energy Crisis Rate Case
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Application to recover approximately $83.6 million in deferred legal and settlement costs
incurred to resolve claims arising from the western energy crisis. This application
requests an overall rate increase of 0.94% and to begin amortizing the costs over a
four-year period beginning June 1, 2007.
In February 2007, NPC entered into a stipulation, with the parties to the case, to
recover the $83.6 million plus carrying charges over a 3-year period beginning June 1,
2007. This stipulation is expressly conditioned upon the PUCN’s acceptance of the
concurrently filed stipulation related to NPC’s 2001 Deferred Energy Case, discussed
below. If the PUCN does not accept both stipulations, this stipulation shall be deemed
withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue
an order on the stipulation.
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NPC 2006 General Rate Case
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Application to reset General Rates. This legislatively mandated filing requests
authorization to increase general rates by $172.4 million which is approximately an 8%
increase. In this application, the Company requested that the Return on
Equity (“ROE”) and Rate of Return (“ROR”) be set at 11.40% and 9.41%, respectively. NPC
expects the new rates to be in effect on or before June 1, 2007.
In February 2007, NPC submitted its certification filing. This filing did not change the
requested ROE, but the ROR decreased to 9.39% and the general revenue increase was
lowered to $156.4 million.
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SPPC 2006 Nevada Electric Deferred Energy Rate Case and BTER Update
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Application to create a new electric DEAA rate and to update the electric BTER. In this
application, SPPC requests to decrease rates by $7.9 million, a decrease of .86%, while
recovering $18.7 million of deferred fuel and purchased power costs. SPPC is seeking
recovery using a symmetrical two-year amortization period beginning July 1, 2007.
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SPPC 2006 Nevada Western Energy Crisis Rate Case
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Application to recover $22.6 million in deferred legal and settlement costs incurred to
resolve claims arising from the western energy crisis. This application requests an
overall rate increase of 0.53% and to begin amortizing the costs over a four-year period
beginning July 1, 2007.
In February 2007, SPPC entered into a stipulation where SPPC replaces its request to
implement rates on July 1, 2007 with a request to establish a regulatory asset to recover
the costs. SPPC further requests authority to recover carrying charges on the regulatory
asset. SPPC may request authority to begin recovering the regulatory asset established
by the PUCN in a future application to change rates. The parties to the stipulation have
requested that the PUCN issue an order by September 30, 2007.
Other Pending Matters
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NPC 2001 Deferred Energy Case
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In July 2006, the Supreme Court of Nevada issued a ruling that will allow NPC to recover
approximately $180 million of deferred energy, which was disallowed in NPC’s 2001
Deferred Energy Case. The decision directs the District Court to remand the matter back
to the PUCN to determine the appropriate rate schedule.
In February 2007, NPC entered into a stipulation where NPC shall be authorized to recover
in rates $189.9 million over ten years beginning on June 1, 2007, with no additional
carrying charges. This stipulation is expressly conditioned upon the PUCN’s acceptance
of the concurrently filed stipulation related to the Western Energy Crisis, discussed
above. If the PUCN does not accept both stipulations, this stipulation shall be deemed
withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue
an order on the stipulation.
Approved Rate Cases
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NPC 2006 Deferred Energy Rate Case and BTER Update
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Application to create a new DEAA rate and to update the going forward BTER. In April
2006, the PUCN approved a new BTER, which would increase purchased fuel and power
revenues by an estimated $112 million. In June 2006, the PUCN approved a negotiated
settlement of the deferred energy phase of the case, which, based on an updated forecast,
reduced the previously approved BTER revenue by approximately $1.6 million and allowed
full recovery of $171.5 million in deferred costs, with an effective date of May 1, 2006.
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SPPC 2006 Nevada Natural Gas and Propane Deferred Energy Rate Case and BTER Update
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Application to create a new DEAA rate and to update the BTER. In October 2006, the PUCN
approved negotiated settlements to recover $1.1 million in deferred natural gas and
propane costs and to set the going forward energy rates such that $1.3 million of new
revenues would be collected. The settlements, combined with the expiration of a previous
natural gas DEAA rate, will yield a 2.5% rate reduction for natural gas customers and a
3.3% increase for propane customers.
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SPPC 2005 Nevada Electric Deferred Energy Rate Case and BTER Update
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Application to create a new electric DEAA rate and to update the electric BTER. In
April 2006, the PUCN approved a new Electric BTER, which will increase purchased fuel and
power revenues by an estimated $31 million. In June 2006, the PUCN approved a negotiated
settlement, which granted SPPC full recovery of $46.7 million in deferred costs during a
two year period beginning July 2006.
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SPPC 2005 Nevada Electric General Rate Case
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Application to reset electric general rates. In April, 2006, the PUCN authorized a 10.6%
ROE and 8.96% ROR and ordered SPPC to reduce general revenues for electric services by
approximately $14 million.
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SPPC 2005 Nevada Gas General Rate Case
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Application to reset gas general rates. In April 2006, the PUCN authorized a 10.6% ROE
and 7.98% ROR and ordered SPPC to increase general revenues for gas services by
approximately $4.5 million.
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SPPC 2006 California Energy Cost Adjustment Clause Rate Case
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Application to reset energy rates. The total request sought to collect an additional
$11.2 million annually for deferred and going forward costs related to fuel and power
purchases. The two requested rate increases total 16.5%. In October 2006, the CPUC
approved the application as filed, with an effective date of November 1, 2006.
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SPPC 2005 California General Rate Case
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Application to reset General Rates. In August 2006, the CPUC approved a settlement
agreement, which beginning on September 2006, allowed SPPC to collect an estimated $4.1
million of additional general revenues.
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Nevada Matters
Nevada Power Company
2007 Deferred Energy Rate Case and BTER Update
In January 2007, NPC filed an electric DEAA rate case and BTER update application with the
PUCN. The application seeks recovery of $75 million of deferred fuel and purchased power costs and
requested to reset NPC’s going forward BTER to reflect anticipated changes in future energy costs.
This application requests a 1.6% decrease in overall rates.
2007 Western Energy Crisis Rate Case
In January 2007, NPC filed an application to recover $83.6 million over four years in deferred
legal and settlement costs incurred to resolve claims associated with power supply contracts
terminated during the western energy crisis. This application requests an overall rate increase of
less than 1%.
In February 2007, NPC entered into a stipulation, with the parties to the case, to recover the
$83.6 million plus carrying charges over a 3-year period beginning June 1, 2007. This stipulation
is expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related
to NPC’s 2001 Deferred Energy Case, discussed below. If the PUCN does not accept both
stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to
litigate. The PUCN has yet to issue an order on the stipulation.
2006 General Rate Case
In November 2006, NPC filed its statutorily required electric general rate case. This filing
requests authorization to:
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Increase annual general revenues by $172.4 million which is approximately an 8% increase
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Set the Return on Equity and Rate of Return at 11.40% and 9.41%, respectively
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Recover 100% of the amortization of the 1999 NPC/SPPC merger costs rather than
the 80% recovery that is currently in general rates
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Implement the PUCN’s previous orders regarding incentive ratemaking for the
Chuck Lenzie Generating Station
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Implement new depreciation rates
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Hearings are scheduled to take place in late March and early April of 2007 with rates expected
to be effective on or before June 1, 2007.
In February 2007, NPC submitted its certification filing which lowered the requested ROR to
9.39% and the general revenues increase was lowered to $156.4 million, representing an overall rate
increase of 7.4%.
2006 Deferred Energy Rate Case and BTER Update
In January 2006, NPC filed an application with the PUCN seeking recovery of $171.5 million of
deferred fuel and purchased power costs and to increase its going forward BTER to reflect
anticipated changes in future energy costs. The application requests an overall rate increase of
approximately 17%.
In April 2006, the PUCN approved an agreement among the interveners and NPC, which, effective
May 1, 2006, set NPC’s BTER rates such that an estimated $112 million (revised by June 2006 DEAA
agreement – see below) of new revenues would be collected for fuel and power purchases in addition
to the start of an $8.4 million collection related to a previous DEAA rate case. Combined, the
approximately $120 million increase represented an overall average rate increase of approximately
6.5%.
In the Deferred Energy portion of the case, NPC had requested authorization to recover $171.5
million of previously incurred purchased fuel and power costs over a one year period. In June
2006, the PUCN approved a negotiated settlement, which specified (1) a reduction of $1.6 million to
the BTER approved in April 2006 based on an updated projection of costs and (2) granted NPC full
recovery of the $171.5 million of deferred costs during a two year period beginning August 2006.
However, the $171.5 million was reduced by a $16.5 million payment previously received by NPC in
connection with the Lenzie acquisition. Under this agreement, the DEAA rate changes required to
asymmetrically recover the deferred balance are scheduled to be implemented during a two year
period such that they will be offset by the expiration of previously approved DEAA rates. As a
result, no rate increase was required.
2001 Deferred Energy Case
In November 2001, NPC made a deferred energy filing with the PUCN seeking repayment for
purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, as
required by law. The application sought to establish a rate to repay purchased fuel and power
costs of $922 million and spread the recovery of the deferred costs, together with a carrying
charge, over a period of not more than three years.
In March 2002, the PUCN issued its Order on the application, allowing NPC to recover $478
million over a three-year period, but disallowing $434 million of deferred purchased fuel and power
costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued
through September 2001 and $20.8 million in carrying charges accrued from October 2001 through
February 2002. The Order stated that the disallowance was based on alleged imprudence in incurring
the disallowed costs. NPC and the Bureau of Consumer Protection (BCP) both sought individual
review of the PUCN Order in the First District Court of Nevada. The District Court affirmed the
PUCN’s decision. Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.
In July 2006, the Supreme Court of Nevada issued a ruling that will allow NPC to recover
approximately $180 million of deferred energy, which was disallowed in NPC’s 2001 Deferred Energy
Case. The decision directs the District Court to remand the matter back to the PUCN to determine
the appropriate rate schedule.
In February 2007, NPC entered into a stipulation where NPC shall be authorized to recover in
rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges.
This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed
stipulation related to the Western Energy Crisis, discussed above. If the PUCN does not accept
both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all
rights to litigate. The PUCN has yet to issue an order on the stipulation.
2006 Integrated Resource Plan
In June 2006, NPC filed its 2006 triennial Integrated Resource Plan with the PUCN. The filing
requested approval to develop new conventional and renewable generation resources, improve NPC’s
transmission system and increase demand side initiatives. The demand side programs are intended to
help customers use electricity more efficiently and also contribute to NPC’s Renewable Portfolio
requirements. The following are the key elements of the filing:
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Requested approval to construct the following supply side resources:
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1.
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Two 750 MW critical coal fired generation units at the
proposed Ely Energy Center in White Pine County, Nevada estimated to be in
service by 2011 and 2013 respectively. Also, part of this project is a
250-mile 500 kV transmission line to integrate the new generation into both
NPC’s and SPPC’s systems and to allow delivery of geothermal resources from
Northern Nevada to NPC and solar powered generation from Southern Nevada to
SPPC.
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Construction of 600 MW of gas fired combustion turbine
peaking generation, 400 MW in service by 2008 and 200 MW in service by 2009.
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Requested the PUCN to designate the Ely Energy Center and the 500kV
transmission intertie as critical facilities under Nevada regulations and
requested incentive ratemaking treatment including “CWIP in rate base” during
construction and, upon completion, a 2% enhanced ROE and accumulation of
depreciation expense in a regulatory asset account from the time the plants are
placed in service until they are included in rates.
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Outlined initiatives, including NPC ownership positions in renewable energy
projects, which are expected to enable NPC to meet Nevada’s Portfolio Standards.
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Requested approval of four new demand side programs and to increase spending
on eight existing demand side programs.
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Outlined NPC’s ten-year $4.7 billion budget for all of the proposed
initiatives.
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In September 2006, NPC provided testimony that modified its request for critical facility
designations and associated incentive ratemaking treatments, which included the withdrawal of the
following:
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Incentive ratemaking treatment for the initial $300 million project
development costs.
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NPC’s request for a specific enhanced ROE in this docket; however, NPC stated
it would resubmit a request for an enhanced ROE in a future filing.
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In October 2006 the PUCN approved a negotiated settlement of NPC’s 2007-2009 Energy Supply
Plan, which was a component of its integrated resource plan filing.
In November 2006, the PUCN issued an order with the findings of that order listed below:
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PUCN granted the Utilities’ request to proceed with the
development of Phase I of the Ely Energy Center and accompanying transmission
line. The PUCN also approved the Utilities’ request of $300 million for
development activities associated with the Ely Energy Center 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 NPC’s request for critical facility designation,
thereby allowing it to qualify for incentives to be determined at a later
date.
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The PUCN also directed the Utilities, upon receipt of the air permit, to
prepare and submit a subsequent filing in the form of a resource plan amendment
(“Ely Energy Center Amendment”) in which they will ask for PUCN approval to
proceed with the construction of the Ely Energy Center and transmission line
based on detailed engineering, construction and cost estimates, and a refined
project schedule.
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The PUCN approved NPC’s request to construct 600 MW of
nominally rated quick start combustion turbine units at the Clark Station at a
cost of approximately $395 million, with approximately 400 MWs of peaking
capacity to be installed prior to the summer of 2008 and approximately 200 MWs
of additional peaking capacity to installed prior to the summer of 2009.
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Material Amendments to NPC’s 2006 Integrated Resource Plan
In January 2007, NPC filed an amendment to its 2006 Integrated Resource Plan
requesting approval to expend $60 million to install new ultra-low emission burners on the four
combustion turbines serving the combined cycle units at the Clark Generating Station.
Material Amendments to NPC’s 2003 Integrated Resource Plan
Request for Authorization to Acquire Land & Land Rights for Transmission Facilities
In January 2006, NPC filed an amendment to its 2003 Integrated Resource Plan requesting
approval to acquire approximately $57 million of strategic investments in land and land rights
necessary for future 500 kV and 230 kV transmission facilities. NPC also requested approval to
accrue a carrying charge on the investments, which would be equal to the current Allowance for
Funds Used During Construction.
In April 2006, the PUCN approved a negotiated agreement that authorizes NPC to invest $37
million in land and land rights and to include authorized investments in the rate base calculation
for its next general rate case.
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Enhanced ROE Due to Early Completion of Lenzie Generating Station
The PUCN designated Lenzie a critical facility and allowed a 2% enhancement to the authorized
ROE when the PUCN approved NPC’s request to acquire the facility. The PUCN further allowed up to
an additional .5% enhanced ROE if the Lenzie Block #1 generator units (two combustion
turbine/generators and one steam turbine/generator) were commercially operable before March 2006
and another .5% ROE enhancement if Block #2 was completed before June 2006.
In January 2006, the first 600 MW combined cycle unit (Block #1) was declared commercially
operable. In April 2006, NPC announced that Lenzie Block #2 was commercially operable. NPC’s
construction costs are projected to be less than the amount authorized by the PUCN. NPC believes
it is eligible to receive a 3% enhancement to the otherwise authorized ROE that will be decided as
a result of its GRC filing that it made in November 2006. See Note 1, Summary of Significant
Accounting Policies of the Condensed Notes to Financial Statements for further discussion on the
accounting for the enhancement.
Sierra Pacific Power Company
2006 Electric Deferred Energy Rate Case and BTER Update
In December 2006, SPPC filed an electric DEAA rate case and BTER update application with the
PUCN. The application seeks recovery of $18.7 million of deferred fuel and purchased power costs
and requested to reset SPPC’s going forward BTER to reflect anticipated changes in future energy
costs. This application requests a 0.86% decrease in overall rates.
2006 Western Energy Crisis Rate Case
In December 2006, SPPC filed an application to recover $22.6 million over four years in
deferred legal and settlement costs incurred to resolve claims associated with power supply
contracts terminated during the western energy crisis. This application requests an overall rate
increase of 0.53%.
In February 2007, SPPC entered into a stipulation where SPPC replaces its request to implement
rates on July 1, 2007 with a request to establish a regulatory asset to recover the costs. SPPC
further requests authority to recover carrying charges on the regulatory asset. SPPC may request
authority to begin recovering the regulatory asset established by the PUCN in a future application
to change rates. The parties to the stipulation have requested that the PUCN issue an order by
September 30, 2007.
2006 Natural Gas and Propane Deferred Energy Rate Case and BTER Update
In May 2006, SPPC’s gas distribution operation filed applications with the PUCN seeking
recovery of deferred natural gas and propane costs accumulated between April 1, 2005 and March 31,
2006. The applications sought to establish a new natural gas DEAA rate to recover $2.5 million of
deferred natural gas costs and a new propane DEAA rate to recover $120 thousand of deferred propane
costs. SPPC also requested authorization to increase going forward natural gas and propane BTER’s
to reflect forecasted gas costs.
In October 2006, the PUCN approved negotiated natural gas and propane settlements which
consolidated the deferred natural gas and propane balances for collection from all gas customers
and reduced the combined balance to $1.1 million. The agreements transferred approximately $1.4
million to other deferral periods and $.1 million to expense accounts. The agreements called for
the cost recovery to occur over a 12 month period beginning December 2006.
The negotiated going forward natural gas rate is expected to recover an additional $1.3
million in revenue, which is a decrease from the originally requested $24.5 million. The decrease
reflects more current natural gas price expectations.
These settlements, combined with the expiration of a previous natural gas DEAA rate will cause
natural gas customer rates to decrease by 2.5% and cause propane customer rates to increase by 3.3
%.
2005 Electric Deferred Energy Rate Case and BTER Update
In December 2005, SPPC filed an electric deferred energy rate case application with the PUCN.
The application sought to establish a rate to collect accumulated fuel and purchased power costs of
$46.7 million from the December 2004 to September 2005 deferral period and $17.5 million from the
previously approved unamortized deferrals, for a total $64.2 million. In June 2006, the PUCN
approved a negotiated settlement, which granted SPPC full recovery of the deferred costs during a
two year period beginning July 2006. Under this agreement, the DEAA rate changes required to
asymmetrically recover the $46.7 million deferred balance are scheduled to be implemented such that
they will be offset by the expiration of previously approved DEAA rates. As a result, no rate
increase was required.
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The application also requested an increase to the BTER. In April 2006, the PUCN issued an
order authorizing SPPC to increase its BTER on May 1, 2006, such that SPPC expects to collect $31
million in new revenues for purchased power. The change represented a 3.5% increase to customer
rates.
2005 Electric and Gas General Rate Cases
In October 2005, SPPC filed a gas general rate case along with its statutorily required
electric general rate case. SPPC’s last gas general rate case was filed in 1992 and the last
electric general rate case was filed in 2003. The following items were requested in the filings:
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Electric general revenue increase: $27 million or 3.4% effective May 1, 2006
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Gas general revenue increase: $8.3 million or 5.4%, effective May 1, 2006
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Electric Return on Equity and Rate of Return: 11.4% and 9.27% respectively
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Gas Return on Equity and Rate of Return: 11.4% and 8.29% respectively
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Approval to continue to recover an allocated amount of the 1999 NPC/SPPC
merger costs from Electric customers
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Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs from Gas customers
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New depreciation rates for Gas and Electric facilities
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In April 2006, the PUCN issued its order to change electric and gas general rates. Although
the order differed from SPPC’s requested filing, the changes did not require material adjustments
to net income for the six months ended June 30, 2006. The PUCN vote resulted in the following
significant items:
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Electric general revenue decrease: approximately $14 million annually or 1.5% effective May 1, 2006.
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Gas general revenue increase: $4.5 million annually or 2.3%, effective May 1, 2006.
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Electric Return on Equity and Rate of Return: 10.6% and 8.96% respectively.
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Gas Return on Equity and Rate of Return: 10.6% and 7.98% respectively.
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Approval to continue recovery of SPPC’s allocated amount of the 1999 NPC/SPPC
merger costs and goodwill from Electric customers.
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Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs and
goodwill from Gas customers.
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New depreciation rates for Gas and Electric facilities.
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Deferred recovery of legal expenses related to the Enron purchased power contract litigation.
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Material Amendments to SPPC’s 2004 Integrated Resource Plan
In July 2006, SPPC filed the thirteenth amendment to its 2004 Integrated Resource Plan. The
following are the key elements of the filing:
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Requested approval to construct two 750 MW critical coal fired generation
units at the proposed Ely Energy Center in White Pine County, Nevada estimated to
be in service by 2011 and 2013 respectively. Also, part of this project is a
250-mile 500 kV transmission line to integrate the new generation into both NPC’s
and SPPC’s systems and to allow delivery of geothermal resources from Northern
Nevada to NPC and solar powered generation from Southern Nevada to SPPC. The
Utilities are currently estimating that 80% of the costs will be allocated to NPC
and 20% will be allocated to SPPC.
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Requested the PUCN to designate the Ely Energy Center and the 500kV
transmission intertie as critical facilities under Nevada regulations and
requested incentive ratemaking treatment including “CWIP in rate base” during
construction and, upon completion, a 2% enhanced ROE and accumulation of
depreciation expense in a regulatory asset account from the time the plants are
placed in service until they are included in rates.
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Requested approval to make certain enhancements to SPPC’s existing fleet of
generators.
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Provided a $3.8 billion total estimate for the Ely Energy Center and outlines
SPPC’s cost for other proposed initiatives totaling approximately $15 million.
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In September 2006, SPPC provided testimony that modified its request for critical facility
designations and associated incentive ratemaking treatments, which included the withdrawal of the
following:
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Incentive ratemaking treatment for the initial $300 million project
development costs.
|
|
|
|
|
•
|
|
SPPC’s request for a specific enhanced ROE in this docket; however, SPPC
stated it would resubmit a request for an enhanced ROE in a future filing.
|
In October 2006 the PUCN approved a negotiated settlement of SPPC’s 2007 Energy Supply Plan
Update, which was a component of its integrated resource plan amendment.
90
In November 2006, the PUCN issued an order with the findings of that order listed below:
|
|
•
|
|
Supply Side Resources
|
|
|
|
|
|
|
The PUCN granted the Utilities’ request to proceed with the development of Phase I
of the Ely Energy Center and accompanying transmission line. The PUCN also approved
the Utilities’ request of $300 million for development activities associated with
the Ely Energy Center 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 SPPC’s request for critical
facility designation, thereby allowing it to qualify for incentives to be
determined at a later date.
|
The PUCN also directed the Utilities, upon receipt of the air permit, to prepare and submit a
subsequent filing in the form of a resource plan amendment (“Ely Energy Center Amendment”) in which
they will ask for PUCN approval to proceed with the construction of the Ely Energy Center and
transmission line based on detailed engineering, construction and cost estimates, and a refined
project schedule.
Other Nevada Matters
Nevada Power Company and Sierra Pacific Power Company
Renewable Portfolio Compliance
In April 2006, the Utilities filed their 2005 Annual Renewable Energy Portfolio Standard
Report with the PUCN (the “Report”). The Report indicates that the Utilities will meet the
non-solar portfolio standard upon PUCN approval of a sale from SPPC to NPC of non-solar portfolio
energy credits. The Utilities requested an exemption from the PUCN for the solar portion of the
portfolio standard.
In September 2006, the PUCN approved a stipulated agreement allowing NPC to purchase from
SPPC, non-solar portfolio energy credits to meet its 2005 compliance year requirements.
In January 2007, the PUCN approved the Annual Report of NPC and SPPC regarding compliance with
the renewable energy portfolio standard for 2005 in accordance with a stipulated agreement that was
filed with the PUCN in November 2006.
California Electric Matters
Sierra Pacific Power Company
2006 Energy Cost Adjustment Clause Rate Case
In April 2006, SPPC filed with the CPUC to reset its “balancing” rate to recover a forecasted
deferred energy cost balance and to increase its “offset” rate for going-forward fuel and power
purchases. The requested increase in the balancing rate is expected to result in $1.1 million
additional revenue and the requested increase in the offset rate is expected to collect an
additional $10.1 million. The total request represents an $11.2 million annual revenue increase or
a 16.5% average increase to customer rates.
In October 2006, the CPUC authorized SPPC’s request as filed.
2005 General Rate Case
In June 2005, SPPC filed a California general rate case requesting $8.1 million of new revenue
from approximately 40,000 California customers. The request represents a 12.7% average increase.
SPPC requested that the new rates become effective on January 1, 2006.
In August 2006, the CPUC approved a settlement agreement, which beginning September 2006,
allowed SPPC to collect an estimated $4.1 million of additional general revenues from its
California customers.
91
Other California Matters
Sierra Pacific Power Company
Senate Bill 1368
In September 2006, California enacted Senate Bill 1368 which requires, among other things,
that load bearing utilities may not undertake new long-term financial commitments for baseload
generation plants if the greenhouse gas (GHG) emission rates for those plants exceed the GHG
emission rate of a combined cycle gas turbine power plant. The legislation also provides that
multi-jurisdictional utilities, including SPPC, will not be subject to the substantive restrictions
of Senate Bill 1368 if the CPUC finds that GHG emissions by those utilities are subject to
regulatory review in at least one other state. On January 25, 2007, the CPUC issued an
order finding that SPPC meets this alternative compliance requirement and that SPPC need only file
annual advice letters with the CPUC attesting that it continues to meet the alternative compliance
requirement.
SPPC is unable to predict the impact that future California legislative or regulatory actions
relating to GHG emissions may have on SPPC.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
As of December 31, 2006, SPR, NPC and SPPC have evaluated their risk related to financial
instruments whose values are subject to market sensitivity. Such instruments are fixed and variable
rate debt. Fair market value is determined using quoted market price for the same or similar issues
or on the current rates offered for debt of the same remaining maturities (dollars in thousands).
December 31, 2006
Expected Maturity Date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
|
|
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
|
Total
|
|
Value
|
|
|
|
|
|
Long-term Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
549,209
|
|
|
$
|
549,209
|
|
|
$
|
568,541
|
|
|
Average Interest Rate
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
7.75
|
%
|
|
|
7.75
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate
|
|
$
|
15
|
|
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
364,000
|
|
|
$
|
1,776,835
|
|
|
$
|
2,140,865
|
|
|
$
|
2,246,234
|
|
|
Average Interest Rate
|
|
|
8.17
|
%
|
|
|
8.17
|
%
|
|
|
—
|
|
|
|
—
|
|
|
|
8.14
|
%
|
|
|
6.58
|
%
|
|
|
6.85
|
%
|
|
|
|
|
|
Variable Rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
192,500
|
|
|
$
|
207,500
|
|
|
$
|
207,500
|
|
|
Average Interest Rate
|
|
|
—
|
|
|
|
—
|
|
|
|
3.63
|
%
|
|
|
—
|
|
|
|
—
|
|
|
|
3.57
|
%
|
|
|
3.57
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate
|
|
$
|
2,400
|
|
|
$
|
322,400
|
|
|
$
|
80,600
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
400,000
|
|
|
$
|
805,400
|
|
|
$
|
819,744
|
|
|
Average Interest Rate
|
|
|
6.40
|
%
|
|
|
7.99
|
%
|
|
|
5.01
|
%
|
|
|
—
|
|
|
|
—
|
|
|
|
6.06
|
%
|
|
|
6.73
|
%
|
|
|
|
|
|
Variable Rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
268,250
|
|
|
$
|
268,250
|
|
|
$
|
268,250
|
|
|
Average Interest Rate
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
3.62
|
%
|
|
|
3.62
|
%
|
|
|
|
|
|
|
|
|
|
Total Debt
|
|
$
|
2,415
|
|
|
$
|
322,415
|
|
|
$
|
95,600
|
|
|
$
|
—
|
|
|
$
|
364,000
|
|
|
$
|
3,186,794
|
|
|
$
|
3,971,224
|
|
|
$
|
4,110,269
|
|
|
|
|
|
92
December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
|
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Thereafter
|
|
|
Total
|
|
|
Value
|
|
|
Long-term Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
659,142
|
|
|
$
|
659,142
|
|
|
$
|
689,131
|
|
|
Average
Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.86
|
%
|
|
|
7.86
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate
|
|
$
|
15
|
|
|
$
|
17
|
|
|
$
|
13
|
|
|
$
|
162,500
|
|
|
$
|
—
|
|
|
$
|
1,741,048
|
|
|
$
|
1,903,593
|
|
|
$
|
1,979,608
|
|
|
Average
Interest Rate
|
|
|
8.17
|
%
|
|
|
8.17
|
%
|
|
|
8.17
|
%
|
|
|
10.88
|
%
|
|
|
|
|
|
|
7.20
|
%
|
|
|
7.52
|
%
|
|
|
|
|
|
Variable Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
15,000
|
|
|
$
|
150,000
|
|
|
$
|
100,000
|
|
|
$
|
265,000
|
|
|
$
|
265,000
|
|
|
Average
Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.74
|
%
|
|
|
5.50
|
%
|
|
|
1.74
|
%
|
|
|
3.87
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate
|
|
$
|
52,400
|
|
|
$
|
2,400
|
|
|
$
|
322,400
|
|
|
$
|
80,420
|
|
|
$
|
—
|
|
|
$
|
537,250
|
|
|
$
|
994,870
|
|
|
$
|
1,013,385
|
|
|
Average
Interest Rate
|
|
|
6.73
|
%
|
|
|
6.40
|
%
|
|
|
7.99
|
%
|
|
|
5.01
|
%
|
|
|
|
|
|
|
6.75
|
%
|
|
|
7.01
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt
|
|
$
|
52,415
|
|
|
$
|
2,417
|
|
|
$
|
322,413
|
|
|
$
|
257,920
|
|
|
$
|
150,000
|
|
|
$
|
3,037,440
|
|
|
$
|
3,822,605
|
|
|
$
|
3,947,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price Risk
Commodity price increases due to changes in market conditions are recovered through the
deferred energy mechanism. Although the Utilities actively manage energy commodity (electric,
natural gas, coal and oil) price risk through their procurement strategies, the ability to recover
commodity price changes through future rates substantially mitigates commodity price risk. However,
the Utilities are subject to cash flow risk due to changes in the value of their open positions and
are subject to regulatory risk because the PUCN may disallow recovery for any costs that it
considers imprudently incurred. The Utilities mitigate both risk associated with its open positions
and regulatory risk through prudent energy supply practices which include the use of long-term fuel
supply agreements, long- term purchase power agreements and derivative instruments such as
forwards, options and swaps to meet the anticipated fuel and power requirements. See Energy Supply
in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations,
for a discussion of the Utilities’ purchased power procurement strategies and Note 13, Commitments
and Contingencies, Regulatory Contingencies, of the Notes to Financial Statements, for a discussion
of amounts subject to regulatory risk.
Credit Risk
The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is
defined as the possibility that a counterparty to one or more contracts will be unable or unwilling
to fulfill its financial or physical obligations to the Utilities because of the counterparty’s
financial condition. The Utilities’ credit risk associated with trading counterparties was
approximately $31.1 million as of December 31, 2006, which decreased significantly from December
31, 2005 due to lower natural gas and power prices in 2006 compared to the high prices experienced
in 2005 as a result of hurricanes in the southern United States. In the event that the trading
counterparties are unable to deliver under their contracts, it may be necessary for the Utilities
to purchase alternative energy at a higher market price.
93
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
|
|
|
|
|
|
Page
|
|
|
Reports of Independent Registered Public Accounting Firm
|
|
|
95
|
|
|
|
|
|
|
|
|
Financial Statements:
|
|
|
|
|
|
|
|
|
|
|
|
Sierra Pacific Resources:
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2006 and 2005
|
|
|
98
|
|
|
Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
99
|
|
|
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
100
|
|
|
Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
101
|
|
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
102
|
|
|
Consolidated Statements of Capitalization as of December 31, 2006 and 2005
|
|
|
103
|
|
|
|
|
|
|
|
|
Nevada Power Company:
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2006 and 2005
|
|
|
105
|
|
|
Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
106
|
|
|
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
107
|
|
|
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
108
|
|
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
109
|
|
|
Consolidated Statements of Capitalization as of December 31, 2006 and 2005
|
|
|
110
|
|
|
|
|
|
|
|
|
Sierra Pacific Power Company:
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2006 and 2005
|
|
|
111
|
|
|
Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
112
|
|
|
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
113
|
|
|
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
114
|
|
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
115
|
|
|
Consolidated Statements of Capitalization as of December 31, 2006 and 2005
|
|
|
116
|
|
|
|
|
|
|
|
|
Notes to Financial Statements for Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company
|
|
|
117
|
|
94
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Sierra Pacific Resources
Reno, Nevada
We have audited the accompanying consolidated balance sheets and statements of capitalization of
Sierra Pacific Resources and subsidiaries as of December 31, 2006 and 2005, and the related
consolidated income statements and statements of comprehensive income, common shareholders’
equity, and cash flows for each of the three years in the period ended December 31, 2006. Our
audits also included the financial statement schedules listed in the Index at Item 15. These
financial statements and financial statement schedules are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial statements and financial
statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of Sierra Pacific Resources and subsidiaries as of December 31, 2006 and
2005, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2006, in conformity with accounting principles generally accepted in the
United States of America. Also, in our opinion, such financial statement schedules, when
considered in relation to the basic consolidated financial statements taken as a whole, present
fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, on January 1, 2006, the Company
adopted the provisions of Statement of Financial Accounting Standards No. 123(R), and on December 31, 2006, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 158.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of the Company’s internal control over financial reporting
as of December 31, 2006, based on the criteria established in
Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
March 1, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of
the Company’s internal control over financial reporting and an unqualified opinion on the
effectiveness of the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Reno, Nevada
March 1, 2007
95
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Las Vegas, Nevada
We have audited the accompanying consolidated balance sheets and statements of capitalization of
Nevada Power Company and subsidiaries as of December 31, 2006 and 2005, and the related
consolidated income statements and statements of comprehensive income, common shareholder’s equity, and cash flows
for each of the three years in the period ended December 31, 2006. Our audits also included the
financial statement schedule listed in the Index at Item 15. These financial statements and
financial statement schedule are the responsibility of the Company’s management. Our responsibility
is to express an opinion on these financial statements and financial statement schedule based on
our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes consideration of internal control over financial reporting as a basis for designing
audit procedures that are appropriate in the circumstances, but not for the purpose of expressing
an opinion on the effectiveness of the Company’s internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of Nevada Power Company and subsidiaries as of December 31, 2006 and 2005,
and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2006, in conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, on December 31, 2006, the Company
adopted the provisions of Statement of Financial Accounting Standards No. 158.
DELOITTE
& TOUCHE LLP
Reno, Nevada
March 1, 2007
96
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Reno, Nevada
We have audited the accompanying consolidated balance sheets and statements of capitalization of
Sierra Pacific Power Company and subsidiaries as of December 31, 2006 and 2005, and the related
consolidated income statements and statements of comprehensive income, common shareholder’s equity, and cash flows
for each of the three years in the period ended December 31, 2006. Our audits also included the
financial statement schedule listed in the Index at Item 15. These financial statements and
financial statement schedule are the responsibility of the Company’s management. Our responsibility
is to express an opinion on these financial statements and financial statement schedule based on
our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes consideration of internal control over financial reporting as a basis for designing
audit procedures that are appropriate in the circumstances, but not for the purpose of expressing
an opinion on the effectiveness of the Company’s internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of Sierra Pacific Power Company and subsidiaries as of December 31, 2006 and
2005, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2006, in conformity with accounting principles generally accepted in the
United States of America. Also, in our opinion, such financial statement schedule, when considered
in relation to the basic consolidated financial statements taken as a whole, presents fairly, in
all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, on December 31, 2006, the Company
adopted the provisions of Statement of Financial Accounting Standards No. 158.
DELOITTE & TOUCHE LLP
Reno, Nevada
March 1, 2007
97
SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Utility Plant at Original Cost:
|
|
|
|
|
|
|
|
|
|
Plant in service
|
|
$
|
7,954,337
|
|
|
$
|
6,801,916
|
|
|
Less accumulated provision for depreciation
|
|
|
2,333,357
|
|
|
|
2,169,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,620,980
|
|
|
|
4,632,600
|
|
|
Construction work-in-progress
|
|
|
466,018
|
|
|
|
765,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,086,998
|
|
|
|
5,397,605
|
|
|
|
|
|
|
|
|
|
|
Investments and other property, net (Note 4)
|
|
|
34,325
|
|
|
|
82,771
|
|
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
115,709
|
|
|
|
172,735
|
|
|
Restricted cash and investments
|
|
|
—
|
|
|
|
67,245
|
|
|
Accounts receivable less allowance for
uncollectible accounts: 2006-$39,566; 2005-$36,229
|
|
|
415,082
|
|
|
|
413,234
|
|
|
Deferred energy costs — electric (Note 1)
|
|
|
168,260
|
|
|
|
253,697
|
|
|
Deferred energy costs — gas (Note 1)
|
|
|
—
|
|
|
|
5,825
|
|
|
Materials, supplies and fuel, at average cost
|
|
|
103,757
|
|
|
|
88,445
|
|
|
Risk management assets (Note 9)
|
|
|
27,305
|
|
|
|
50,226
|
|
|
Deferred
income taxes (Note 10)
|
|
|
55,546
|
|
|
|
—
|
|
|
Deposits and prepayments for energy
|
|
|
15,968
|
|
|
|
45,054
|
|
|
Other
|
|
|
31,580
|
|
|
|
26,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
933,207
|
|
|
|
1,123,005
|
|
|
|
|
|
|
|
|
|
|
Deferred Charges and Other Assets:
|
|
|
|
|
|
|
|
|
|
Goodwill (Note 18)
|
|
|
469
|
|
|
|
22,877
|
|
|
Deferred energy costs — electric (Note 1)
|
|
|
382,286
|
|
|
|
255,312
|
|
|
Deferred energy costs — gas (Note 1)
|
|
|
—
|
|
|
|
845
|
|
|
Regulatory
tax asset (Note 10)
|
|
|
263,170
|
|
|
|
249,261
|
|
|
Regulatory
asset for pension plans (Note 1)
|
|
|
223,218
|
|
|
|
—
|
|
|
Other regulatory assets
|
|
|
668,624
|
|
|
|
568,145
|
|
|
Risk management assets (Note 9)
|
|
|
7,586
|
|
|
|
—
|
|
|
Risk management regulatory assets — net (Note 9)
|
|
|
122,911
|
|
|
|
—
|
|
|
Unamortized debt issuance costs
|
|
|
67,106
|
|
|
|
63,395
|
|
|
Other
|
|
|
42,176
|
|
|
|
107,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,777,546
|
|
|
|
1,267,165
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
8,832,076
|
|
|
$
|
7,870,546
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common shareholders’ equity
|
|
$
|
2,622,297
|
|
|
$
|
2,060,154
|
|
|
Preferred stock
|
|
|
—
|
|
|
|
50,000
|
|
|
Long-term debt
|
|
|
4,001,542
|
|
|
|
3,817,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,623,839
|
|
|
|
5,927,276
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
8,348
|
|
|
|
58,909
|
|
|
Accounts payable
|
|
|
282,463
|
|
|
|
263,100
|
|
|
Accrued interest
|
|
|
56,426
|
|
|
|
58,585
|
|
|
Dividends declared
|
|
|
73
|
|
|
|
1,043
|
|
|
Accrued salaries and benefits
|
|
|
33,146
|
|
|
|
32,186
|
|
|
Current
income taxes payable (Note 10)
|
|
|
5,914
|
|
|
|
3,159
|
|
|
Deferred
income taxes (Note 10)
|
|
|
—
|
|
|
|
129,041
|
|
|
Risk management liabilities (Note 9)
|
|
|
123,065
|
|
|
|
16,580
|
|
|
Accrued taxes
|
|
|
6,290
|
|
|
|
6,540
|
|
|
Contract termination liabilities
|
|
|
—
|
|
|
|
129,000
|
|
|
Other current liabilities
|
|
|
60,349
|
|
|
|
56,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
576,074
|
|
|
|
754,867
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 13)
|
|
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes (Note 10)
|
|
|
791,428
|
|
|
|
451,924
|
|
|
Deferred investment tax credit
|
|
|
35,218
|
|
|
|
38,625
|
|
|
Regulatory
tax liability (Note 10)
|
|
|
34,075
|
|
|
|
38,224
|
|
|
Customer advances for construction
|
|
|
91,895
|
|
|
|
170,061
|
|
|
Accrued retirement benefits
|
|
|
226,420
|
|
|
|
71,810
|
|
|
Risk management liabilities (Note 9)
|
|
|
10,746
|
|
|
|
—
|
|
|
Risk management regulatory liability — net (Note 9)
|
|
|
—
|
|
|
|
15,605
|
|
|
Regulatory
liabilities (Note 1)
|
|
|
301,903
|
|
|
|
284,438
|
|
|
Other
|
|
|
140,478
|
|
|
|
117,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,632,163
|
|
|
|
1,188,403
|
|
|
|
|
|
|
|
|
|
|
TOTAL CAPITALIZATION AND LIABILITIES
|
|
$
|
8,832,076
|
|
|
$
|
7,870,546
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
98
SIERRA PACIFIC RESOURCES
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
OPERATING REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
3,144,243
|
|
|
$
|
2,850,694
|
|
|
$
|
2,666,000
|
|
|
Gas
|
|
|
210,068
|
|
|
|
178,270
|
|
|
|
153,752
|
|
|
Other
|
|
|
1,639
|
|
|
|
1,278
|
|
|
|
5,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,355,950
|
|
|
|
3,030,242
|
|
|
|
2,824,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power
|
|
|
1,109,440
|
|
|
|
1,315,986
|
|
|
|
1,069,302
|
|
|
Fuel for power generation
|
|
|
800,585
|
|
|
|
510,736
|
|
|
|
459,478
|
|
|
Gas purchased for resale
|
|
|
160,739
|
|
|
|
140,850
|
|
|
|
121,526
|
|
|
Deferred energy costs disallowed
|
|
|
—
|
|
|
|
—
|
|
|
|
1,586
|
|
|
Deferral of energy costs — electric – net
|
|
|
139,365
|
|
|
|
(37,558
|
)
|
|
|
143,033
|
|
|
Deferral of energy costs — gas – net
|
|
|
6,947
|
|
|
|
(749
|
)
|
|
|
(4,136
|
)
|
|
Impairment of goodwill
|
|
|
—
|
|
|
|
—
|
|
|
|
11,695
|
|
|
Reinstatement of deferred energy (Note 13)
|
|
|
(178,825
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Other
|
|
|
367,198
|
|
|
|
363,802
|
|
|
|
335,998
|
|
|
Maintenance
|
|
|
93,172
|
|
|
|
78,730
|
|
|
|
78,907
|
|
|
Depreciation and amortization
|
|
|
228,875
|
|
|
|
214,662
|
|
|
|
205,922
|
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes
(Note 10)
|
|
|
91,571
|
|
|
|
39,185
|
|
|
|
22,739
|
|
|
Other than income
|
|
|
48,086
|
|
|
|
45,920
|
|
|
|
44,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,867,153
|
|
|
|
2,671,564
|
|
|
|
2,490,938
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
488,797
|
|
|
|
358,678
|
|
|
|
333,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for other funds used during construction
|
|
|
18,226
|
|
|
|
20,322
|
|
|
|
5,948
|
|
|
Interest accrued on deferred energy
|
|
|
27,898
|
|
|
|
27,442
|
|
|
|
25,332
|
|
|
Early debt conversion fees
|
|
|
—
|
|
|
|
(54,000
|
)
|
|
|
—
|
|
|
Disallowed merger costs
|
|
|
—
|
|
|
|
—
|
|
|
|
(5,890
|
)
|
|
Disallowed plant costs
|
|
|
—
|
|
|
|
—
|
|
|
|
(47,092
|
)
|
|
Carrying
charge for Lenzie (Note 1)
|
|
|
33,440
|
|
|
|
—
|
|
|
|
—
|
|
|
Gain on sale of investment
|
|
|
62,927
|
|
|
|
—
|
|
|
|
—
|
|
|
Other income
|
|
|
37,123
|
|
|
|
41,200
|
|
|
|
35,313
|
|
|
Other expense
|
|
|
(23,497
|
)
|
|
|
(18,645
|
)
|
|
|
(13,770
|
)
|
|
Income
(taxes) / benefits (Note 10)
|
|
|
(54,034
|
)
|
|
|
(3,933
|
)
|
|
|
4,689
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
102,083
|
|
|
|
12,386
|
|
|
|
4,530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Before Interest Charges
|
|
|
590,880
|
|
|
|
371,064
|
|
|
|
338,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
294,488
|
|
|
|
302,668
|
|
|
|
313,305
|
|
|
Interest for Energy Suppliers (Note 13)
|
|
|
—
|
|
|
|
(17,221
|
)
|
|
|
(35,170
|
)
|
|
Other
|
|
|
33,719
|
|
|
|
24,171
|
|
|
|
37,998
|
|
|
Allowance for borrowed funds used during construction
|
|
|
(17,119
|
)
|
|
|
(24,691
|
)
|
|
|
(8,587
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
311,088
|
|
|
|
284,927
|
|
|
|
307,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME FROM CONTINUING OPERATIONS
|
|
|
279,792
|
|
|
|
86,137
|
|
|
|
30,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCONTINUED OPERATIONS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on the sale of discontinued operations (net of income
taxes of ($877))
|
|
|
—
|
|
|
|
—
|
|
|
|
1,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PREFERRED STOCK DIVIDEND REQUIREMENTS OF
SUBSIDIARY AND PREMIUM ON REDEMPTION
|
|
|
2,341
|
|
|
|
3,900
|
|
|
|
3,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME APPLICABLE TO COMMON STOCK
|
|
$
|
277,451
|
|
|
$
|
82,237
|
|
|
$
|
28,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount per share basic and diluted — (Note 16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
1.34
|
|
|
$
|
0.46
|
|
|
$
|
0.17
|
|
|
Gain on sale of discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.01
|
|
|
Net income applicable to common stock
|
|
$
|
1.33
|
|
|
$
|
0.44
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares of Common Stock Outstanding — basic
|
|
|
208,531,134
|
|
|
|
185,548,314
|
|
|
|
183,080,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares of Common Stock Outstanding — diluted
|
|
|
209,020,896
|
|
|
|
185,932,504
|
|
|
|
183,400,303
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
99
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
NET
INCOME APPLICABLE TO COMMON STOCK
|
|
$
|
277,451
|
|
|
$
|
82,237
|
|
|
$
|
28,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in market value of risk management assets and
liabilities as of December 31 (Net of taxes of $1,155 and ($950) in 2005 and 2004, respectively)
|
|
|
—
|
|
|
|
(2,146
|
)
|
|
|
1,763
|
|
|
Minimum pension liability adjustment (Net of taxes of ($1,132), $1,569 and ($15,486) in 2006, 2005 and
2004, respectively)
|
|
|
2,106
|
|
|
|
(4,311
|
)
|
|
|
29,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
2,106
|
|
|
|
(6,457
|
)
|
|
|
31,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
$
|
279,557
|
|
|
$
|
75,780
|
|
|
$
|
59,738
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements
100
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
$
|
200,792
|
|
|
$
|
117,469
|
|
|
$
|
117,236
|
|
|
Stock issuance/exchange, CSIP, DRP, ESPP and other
|
|
|
20,238
|
|
|
|
83,323
|
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
|
221,030
|
|
|
|
200,792
|
|
|
|
117,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Paid-In Capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
2,220,896
|
|
|
|
1,818,453
|
|
|
|
1,815,202
|
|
|
Premium on issuance/exchange of common stock
|
|
|
260,600
|
|
|
|
405,767
|
|
|
|
563
|
|
|
Common Stock issuance costs
|
|
|
(857
|
)
|
|
|
(6,486
|
)
|
|
|
—
|
|
|
Revaluation of investment
|
|
|
—
|
|
|
|
119
|
|
|
|
1,690
|
|
|
Value of derivative transferred to equity
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
CSIP, DRP, ESPP and other
|
|
|
2,605
|
|
|
|
3,043
|
|
|
|
998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
2,483,244
|
|
|
|
2,220,896
|
|
|
|
1,818,453
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained Earnings (Deficit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
(355,883
|
)
|
|
|
(438,112
|
)
|
|
|
(466,683
|
)
|
|
Net Income applicable to Common Stock
|
|
|
277,451
|
|
|
|
82,237
|
|
|
|
28,571
|
|
|
Common stock dividends declared, net of adjustments
|
|
|
—
|
|
|
|
(8
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
(78,432
|
)
|
|
|
(355,883
|
)
|
|
|
(438,112
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
(5,651
|
)
|
|
|
806
|
|
|
|
(30,361
|
)
|
|
Adoption of SFAS No. 133 - Accounting for Derivative Instruments and
Hedging Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in market value of risk management assets and liabilities as of
December 31 (Net of taxes of $1,155 and ($950) in 2005 and 2004, respectively)
|
|
|
—
|
|
|
|
(2,146
|
)
|
|
|
1,763
|
|
|
Minimum pension liability adjustment (Net of taxes of ($1,132), $1,569 and ($15,486)
in 2006, 2005 and 2004, respectively)
|
|
|
2,106
|
|
|
|
(4,311
|
)
|
|
|
29,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
(3,545
|
)
|
|
|
(5,651
|
)
|
|
|
806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Common Shareholders’ Equity at End of Year
|
|
$
|
2,622,297
|
|
|
$
|
2,060,154
|
|
|
$
|
1,498,616
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements
101
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended December 31
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
applicable to common stock
|
|
$
|
277,451
|
|
|
$
|
82,237
|
|
|
$
|
28,571
|
|
|
Non-cash items included in net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
228,875
|
|
|
|
214,662
|
|
|
|
205,922
|
|
|
Deferred taxes and deferred investment tax credit
|
|
|
136,026
|
|
|
|
41,609
|
|
|
|
33,690
|
|
|
AFUDC
|
|
|
(18,226
|
)
|
|
|
(45,013
|
)
|
|
|
(14,536
|
)
|
|
Amortization of deferred energy costs – electric
|
|
|
166,821
|
|
|
|
188,221
|
|
|
|
265,418
|
|
|
Amortization of deferred energy costs – gas
|
|
|
6,234
|
|
|
|
1,446
|
|
|
|
3,242
|
|
|
Deferred energy costs disallowed
|
|
|
—
|
|
|
|
—
|
|
|
|
1,586
|
|
|
Goodwill impairment
|
|
|
—
|
|
|
|
—
|
|
|
|
11,695
|
|
|
Plant costs disallowed
|
|
|
—
|
|
|
|
—
|
|
|
|
47,092
|
|
|
Reinstatement of deferred energy
|
|
|
(178,825
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Carrying charge on Lenzie plant
|
|
|
(33,440
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Gain on sale of investment
|
|
|
(62,927
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Impairment of assets of subsidiary
|
|
|
—
|
|
|
|
—
|
|
|
|
10,997
|
|
|
Gain on sale of discontinued operations
|
|
|
—
|
|
|
|
—
|
|
|
|
(2,506
|
)
|
|
Other
|
|
|
24,650
|
|
|
|
(219)
|
|
|
|
(23,453)
|
|
|
Changes in certain assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(43,214
|
)
|
|
|
(92,452
|
)
|
|
|
(19,198
|
)
|
|
Deferral of energy costs – electric
|
|
|
(54,737
|
)
|
|
|
(241,103
|
)
|
|
|
(152,140
|
)
|
|
Deferral of energy costs – gas
|
|
|
436
|
|
|
|
(2,519
|
)
|
|
|
(7,480
|
)
|
|
Deferral of energy costs — terminated suppliers
|
|
|
8,741
|
|
|
|
218,040
|
|
|
|
4,551
|
|
|
Materials, supplies and fuel
|
|
|
(15,312
|
)
|
|
|
(12,251
|
)
|
|
|
3,331
|
|
|
Other current assets
|
|
|
24,050
|
|
|
|
20,663
|
|
|
|
5,721
|
|
|
Accounts payable
|
|
|
(2,739
|
)
|
|
|
55,985
|
|
|
|
13,623
|
|
|
Payment to terminating supplier
|
|
|
(65,368
|
)
|
|
|
—
|
|
|
|
(61,129
|
)
|
|
Proceeds from claim on terminating supplier
|
|
|
41,365
|
|
|
|
—
|
|
|
|
—
|
|
|
Other current liabilities
|
|
|
2,356
|
|
|
|
(162,416
|
)
|
|
|
20,306
|
|
|
Risk Management assets and liabilities
|
|
|
(5,950
|
)
|
|
|
(6,685
|
)
|
|
|
8,487
|
|
|
Other assets
|
|
|
(10,122
|
)
|
|
|
(9,950
|
)
|
|
|
6,168
|
|
|
Other liabilities
|
|
|
3,297
|
|
|
|
(15,659
|
)
|
|
|
(42,476
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash from Operating Activities
|
|
|
429,442
|
|
|
|
234,596
|
|
|
|
347,482
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS USED BY INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to utility plant
|
|
|
(986,019
|
)
|
|
|
(686,394
|
)
|
|
|
(614,411
|
)
|
|
AFUDC
|
|
|
18,226
|
|
|
|
45,013
|
|
|
|
14,536
|
|
|
Customer advances for construction
|
|
|
17,348
|
|
|
|
27,358
|
|
|
|
16,197
|
|
|
Contributions in aid of construction
|
|
|
38,792
|
|
|
|
23,351
|
|
|
|
26,457
|
|
|
Proceeds from sale of investment
|
|
|
99,730
|
|
|
|
—
|
|
|
|
—
|
|
|
Proceeds from sale of discontinued operations
|
|
|
—
|
|
|
|
—
|
|
|
|
4,471
|
|
|
Investments in subsidiaries and other property — net
|
|
|
8,423
|
|
|
|
10,200
|
|
|
|
16,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash used by Investing Activities
|
|
|
(803,500
|
)
|
|
|
(580,472
|
)
|
|
|
(536,451
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in short-term borrowings
|
|
|
—
|
|
|
|
—
|
|
|
|
(25,000
|
)
|
|
Change in restricted cash and investments
|
|
|
3,612
|
|
|
|
23,711
|
|
|
|
27,382
|
|
|
Proceeds from issuance of long-term debt
|
|
|
2,491,883
|
|
|
|
370,211
|
|
|
|
965,000
|
|
|
Retirement of long-term debt
|
|
|
(2,407,745
|
)
|
|
|
(373,938
|
)
|
|
|
(693,538
|
)
|
|
Redemption of preferred stock
|
|
|
(51,366
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Sale of common stock, net of issuance cost
|
|
|
282,594
|
|
|
|
236,208
|
|
|
|
3,488
|
|
|
Dividends paid
|
|
|
(1,945
|
)
|
|
|
(3,911
|
)
|
|
|
(3,821
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash from Financing Activities
|
|
|
317,033
|
|
|
|
252,281
|
|
|
|
273,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(57,025
|
)
|
|
|
(93,595
|
)
|
|
|
84,542
|
|
|
Beginning Balance in Cash and Cash Equivalents
|
|
|
172,734
|
|
|
|
266,330
|
|
|
|
181,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending Balance in Cash and Cash Equivalents
|
|
$
|
115,709
|
|
|
$
|
172,735
|
|
|
$
|
266,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosures of Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during period for:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
338,665
|
|
|
$
|
330,889
|
|
|
$
|
339,718
|
|
|
Income taxes
|
|
$
|
4,726
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange of Convertible Debt for SPR Common Stock
|
|
$
|
—
|
|
|
$
|
248,168
|
|
|
$
|
—
|
|
The accompanying notes are an integral part of the financial statements
102
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Common Shareholder’s Equity:
|
|
|
|
|
|
|
|
|
|
Common stock, $1.00 par value, authorized 350 million; issued
and outstanding 2006: 221,030,000 shares; issued and outstanding
2005: 200,792,000 shares issued and outstanding
|
|
$
|
221,030
|
|
|
$
|
200,792
|
|
|
Other paid-in capital
|
|
|
2,483,244
|
|
|
|
2,220,896
|
|
|
Retained Deficit
|
|
|
(78,432
|
)
|
|
|
(355,883
|
)
|
|
Accumulated other comprehensive Income (Loss)
|
|
|
(3,545
|
)
|
|
|
(5,651
|
)
|
|
|
|
|
|
|
|
|
|
Total Common Shareholder’s Equity
|
|
|
2,622,297
|
|
|
|
2,060,154
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock of Subsidiaries:
|
|
|
|
|
|
|
|
|
|
Not subject to mandatory redemption; 2005: 2,000,000 shares
outstanding;
$25 stated value
|
|
|
|
|
|
|
|
|
|
SPPC Class A Series 1; $1.95 dividend
|
|
|
—
|
|
|
|
50,000
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
Secured Debt
|
|
|
|
|
|
|
|
|
|
First Mortgage Bonds
|
|
|
|
|
|
|
|
|
|
8.50% NPC Series Z due 2023
|
|
|
—
|
|
|
|
35,000
|
|
|
Debt Secured by First Mortgage Bonds
|
|
|
|
|
|
|
|
|
|
Revenue Bonds
|
|
|
|
|
|
|
|
|
|
Nevada Power Company
|
|
|
|
|
|
|
|
|
|
6.60% NPC Series 1992B due 2019
|
|
|
—
|
|
|
|
39,500
|
|
|
6.70% NPC Series 1992A due 2022
|
|
|
—
|
|
|
|
105,000
|
|
|
7.20% NPC Series 1992C due 2022
|
|
|
—
|
|
|
|
78,000
|
|
|
Sierra Pacific Power Company
|
|
|
|
|
|
|
|
|
|
6.35% SPPC Series 1992B due 2012
|
|
|
—
|
|
|
|
1,000
|
|
|
6.55% SPPC Series 1987 due 2013
|
|
|
—
|
|
|
|
39,500
|
|
|
6.30% SPPC Series 1987 due 2014
|
|
|
—
|
|
|
|
45,000
|
|
|
6.65% SPPC Series 1987 due 2017
|
|
|
—
|
|
|
|
92,500
|
|
|
6.55% SPPC Series 1990 due 2020
|
|
|
—
|
|
|
|
20,000
|
|
|
6.30% SPPC Series 1992A due 2022
|
|
|
—
|
|
|
|
10,250
|
|
|
5.90% SPPC Series 1993A due 2023
|
|
|
—
|
|
|
|
9,800
|
|
|
5.90% SPPC Series 1993B due 2023
|
|
|
—
|
|
|
|
30,000
|
|
|
6.70% SPPC Series 1992 due 2032
|
|
|
—
|
|
|
|
21,200
|
|
|
Medium Term Notes
|
|
|
|
|
|
|
|
|
|
Sierra Pacific Power Company
|
|
|
|
|
|
|
|
|
|
6.62% to 6.83% SPPC Series C due 2006
|
|
|
—
|
|
|
|
50,000
|
|
|
6.95% to 8.61% SPPC Series A due 2022
|
|
|
—
|
|
|
|
110,000
|
|
|
7.10% to 7.14% SPPC Series B due 2023
|
|
|
—
|
|
|
|
58,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
—
|
|
|
|
744,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt Secured by General and Refunding Mortgage Securities
|
|
|
|
|
|
|
|
|
|
Nevada Power Company
|
|
|
|
|
|
|
|
|
|
10.88% NPC Series E due 2009
|
|
|
—
|
|
|
|
162,500
|
|
|
8.25% NPC Series A due 2011
|
|
|
350,000
|
|
|
|
350,000
|
|
|
6.50% NPC Series I due 2012
|
|
|
130,000
|
|
|
|
130,000
|
|
|
9.00% NPC Series G due 2013
|
|
|
227,500
|
|
|
|
227,500
|
|
|
5.875% NPC Series L due 2015
|
|
|
250,000
|
|
|
|
250,000
|
|
|
5.95% NPC Series M due 2016
|
|
|
210,000
|
|
|
|
—
|
|
|
6.65% NPC Series N due 2036
|
|
|
370,000
|
|
|
|
—
|
|
|
6.50% NPC Series O due 2018
|
|
|
325,000
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
1,862,500
|
|
|
|
1,120,000
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
(Continued)
103
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Sierra Pacific Power Company
|
|
|
|
|
|
|
|
|
|
8.00% SPPC Series A due 2008
|
|
|
320,000
|
|
|
|
320,000
|
|
|
6.25% SPPC Series H due 2012
|
|
|
100,000
|
|
|
|
100,000
|
|
|
6.00% SPPC Series M due 2016
|
|
|
300,000
|
|
|
|
—
|
|
|
5.00% SPPC Series 2001 due 2036
|
|
|
80,000
|
|
|
|
80,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
800,000
|
|
|
|
500,000
|
|
|
|
|
|
|
|
|
|
|
Variable Rate Notes
|
|
|
|
|
|
|
|
|
|
Nevada Power Company
|
|
|
|
|
|
|
|
|
|
NPC PCRB Series 2000B due 2009
|
|
|
15,000
|
|
|
|
15,000
|
|
|
NPC IDRB Series 2000A due 2020
|
|
|
100,000
|
|
|
|
100,000
|
|
|
NPC PCRB Series 2006 due 2036
|
|
|
39,500
|
|
|
|
—
|
|
|
NPC PCRB Series 2006A due 2032
|
|
|
40,000
|
|
|
|
—
|
|
|
NPC PCRB Series 2006B due 2039
|
|
|
13,000
|
|
|
|
—
|
|
|
NPC Revolving Credit Facility
|
|
|
—
|
|
|
|
150,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
207,500
|
|
|
|
265,000
|
|
|
|
|
|
|
|
|
|
|
Sierra Pacific Power Company
|
|
|
|
|
|
|
|
|
|
SPPC PCRB Series 2006 due 2029
|
|
|
49,750
|
|
|
|
—
|
|
|
SPPC PCRB Series 2006A due 2031
|
|
|
58,700
|
|
|
|
—
|
|
|
SPPC PCRB Series 2006B due 2036
|
|
|
75,000
|
|
|
|
—
|
|
|
SPPC PCRB Series 2006C due 2036
|
|
|
84,800
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
268,250
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Debt
|
|
|
|
|
|
|
|
|
|
Revenue Bonds
|
|
|
|
|
|
|
|
|
|
Nevada Power Company
|
|
|
|
|
|
|
|
|
|
5.30% NPC Series 1995D due 2011
|
|
|
14,000
|
|
|
|
14,000
|
|
|
5.35% NPC Series 1995E due 2022
|
|
|
—
|
|
|
|
13,000
|
|
|
5.45% NPC Series 1995D due 2023
|
|
|
6,300
|
|
|
|
6,300
|
|
|
5.50% NPC Series 1995C due 2030
|
|
|
44,000
|
|
|
|
44,000
|
|
|
5.60% NPC Series 1995A due 2030
|
|
|
76,750
|
|
|
|
76,750
|
|
|
5.90% NPC Series 1995B due 2030
|
|
|
85,000
|
|
|
|
85,000
|
|
|
5.80% NPC Series 1997B due 2032
|
|
|
—
|
|
|
|
20,000
|
|
|
5.90% NPC Series 1997A due 2032
|
|
|
52,285
|
|
|
|
52,285
|
|
|
6.38% NPC Series 1996 due 2036
|
|
|
—
|
|
|
|
20,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
278,335
|
|
|
|
331,335
|
|
|
|
|
|
|
|
|
|
|
Other Notes
|
|
|
|
|
|
|
|
|
|
Sierra Pacific Resources
|
|
|
|
|
|
|
|
|
|
7.803% SPR Senior Notes due 2012
|
|
|
74,170
|
|
|
|
99,142
|
|
|
8.625% SPR Notes due 2014
|
|
|
250,039
|
|
|
|
335,000
|
|
|
6.75% SPR Senior Notes due 2017
|
|
|
225,000
|
|
|
|
225,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal, excluding current portion
|
|
|
549,209
|
|
|
|
659,142
|
|
|
|
|
|
|
|
|
|
|
Unamortized bond premium and discount, net
|
|
|
(11,813
|
)
|
|
|
(3,495
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nevada Power Company
|
|
|
|
|
|
|
|
|
|
8.2% Junior Subordinated Debentures of NPC, due 2037
|
|
|
—
|
|
|
|
122,548
|
|
|
7.75% Junior Subordinated Debentures of NPC, due 2038
|
|
|
—
|
|
|
|
72,165
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
—
|
|
|
|
194,713
|
|
|
|
|
|
|
|
|
|
|
Obligations under capital leases
|
|
|
50,479
|
|
|
|
56,921
|
|
|
Current maturities and sinking fund requirements
|
|
|
(8,348
|
)
|
|
|
(58,909
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Other, excluding current portion
|
|
|
5,430
|
|
|
|
7,665
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt
|
|
|
4,001,542
|
|
|
|
3,817,122
|
|
|
|
|
|
|
|
|
|
|
TOTAL CAPITALIZATION
|
|
$
|
6,623,839
|
|
|
$
|
5,927,276
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
(Concluded)
104
NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Utility Plant at Original Cost:
|
|
|
|
|
|
|
|
|
|
Plant in service
|
|
$
|
5,187,665
|
|
|
$
|
4,106,489
|
|
|
Less accumulated provision for depreciation
|
|
|
1,276,192
|
|
|
|
1,128,209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,911,473
|
|
|
|
2,978,280
|
|
|
Construction work-in-progress
|
|
|
238,518
|
|
|
|
698,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,149,991
|
|
|
|
3,676,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments and other property, net (Note 4)
|
|
|
22,176
|
|
|
|
29,249
|
|
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
36,633
|
|
|
|
98,681
|
|
|
Restricted cash
|
|
|
—
|
|
|
|
52,374
|
|
|
Accounts receivable less allowance for uncollectible accounts:
|
|
|
|
|
|
|
|
|
|
2006-$32,834; 2005-$30,386
|
|
|
244,623
|
|
|
|
232,086
|
|
|
Accounts receivable, affiliated companies
|
|
|
—
|
|
|
|
3,738
|
|
|
Deferred energy costs — electric (Note 1)
|
|
|
129,304
|
|
|
|
186,355
|
|
|
Materials, supplies and fuel, at average cost
|
|
|
60,754
|
|
|
|
46,835
|
|
|
Risk management assets (Note 9)
|
|
|
16,378
|
|
|
|
22,404
|
|
|
Deferred
income taxes (Note 10)
|
|
|
72,294
|
|
|
|
—
|
|
|
Deposits and prepayments for energy
|
|
|
7,056
|
|
|
|
16,303
|
|
|
Other
|
|
|
19,901
|
|
|
|
16,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
586,943
|
|
|
|
674,851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Charges and Other Assets:
|
|
|
|
|
|
|
|
|
|
Deferred energy costs — electric (Note 1)
|
|
|
359,589
|
|
|
|
214,587
|
|
|
Regulatory
tax asset (Note 10)
|
|
|
153,471
|
|
|
|
155,304
|
|
|
Regulatory
asset for pension plans (Note 1)
|
|
|
113,646
|
|
|
|
|
|
|
Other regulatory assets (Note 1)
|
|
|
440,369
|
|
|
|
362,567
|
|
|
Risk management assets
|
|
|
5,379
|
|
|
|
—
|
|
|
Risk management regulatory assets — net (Note 9)
|
|
|
83,886
|
|
|
|
—
|
|
|
Unamortized debt issuance costs
|
|
|
38,856
|
|
|
|
37,157
|
|
|
Other
|
|
|
33,209
|
|
|
|
23,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,228,405
|
|
|
|
793,335
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
5,987,515
|
|
|
$
|
5,173,921
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common shareholder’s equity
|
|
$
|
2,172,198
|
|
|
$
|
1,762,089
|
|
|
Long-term debt
|
|
|
2,380,139
|
|
|
|
2,214,063
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,552,337
|
|
|
|
3,976,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
5,948
|
|
|
|
6,509
|
|
|
Accounts payable
|
|
|
148,003
|
|
|
|
164,169
|
|
|
Accounts payable, affiliated companies
|
|
|
20,656
|
|
|
|
—
|
|
|
Accrued interest
|
|
|
37,010
|
|
|
|
33,031
|
|
|
Dividends declared
|
|
|
13,545
|
|
|
|
397
|
|
|
Accrued salaries and benefits
|
|
|
14,989
|
|
|
|
15,537
|
|
|
Current
income taxes payable (Note 10)
|
|
|
3,981
|
|
|
|
3,159
|
|
|
Intercompany Income taxes payable
|
|
|
884
|
|
|
|
—
|
|
|
Deferred
income taxes (Note 10)
|
|
|
—
|
|
|
|
57,392
|
|
|
Risk management liabilities (Note 9)
|
|
|
84,674
|
|
|
|
10,125
|
|
|
Accrued taxes
|
|
|
2,671
|
|
|
|
2,817
|
|
|
Contract termination liabilities
|
|
|
—
|
|
|
|
89,784
|
|
|
Other current liabilities
|
|
|
48,225
|
|
|
|
46,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
380,586
|
|
|
|
429,345
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 13)
|
|
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes (Note 10)
|
|
|
599,747
|
|
|
|
362,973
|
|
|
Deferred investment tax credit
|
|
|
15,213
|
|
|
|
16,832
|
|
|
Regulatory
tax liability (Note 10)
|
|
|
13,451
|
|
|
|
15,068
|
|
|
Customer advances for construction
|
|
|
60,040
|
|
|
|
98,056
|
|
|
Accrued retirement benefits
|
|
|
90,474
|
|
|
|
22,203
|
|
|
Risk management liabilities (Note 9)
|
|
|
7,061
|
|
|
|
—
|
|
|
Risk management regulatory liability — net (Note 9)
|
|
|
—
|
|
|
|
590
|
|
|
Regulatory liabilities (Note 1)
|
|
|
171,298
|
|
|
|
173,527
|
|
|
Other
|
|
|
97,308
|
|
|
|
79,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,054,592
|
|
|
|
768,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL CAPITALIZATION AND LIABILITIES
|
|
$
|
5,987,515
|
|
|
$
|
5,173,921
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
105
NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
OPERATING REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
2,124,081
|
|
|
$
|
1,883,267
|
|
|
$
|
1,784,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power
|
|
|
764,850
|
|
|
|
963,888
|
|
|
|
764,347
|
|
|
Fuel for power generation
|
|
|
552,959
|
|
|
|
277,083
|
|
|
|
235,404
|
|
|
Deferred energy costs disallowed
|
|
|
—
|
|
|
|
—
|
|
|
|
1,586
|
|
|
Deferral of energy costs-net
|
|
|
92,322
|
|
|
|
(45,668
|
)
|
|
|
135,973
|
|
|
Reinstatement of deferred energy (Note 13)
|
|
|
(178,825
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Other
|
|
|
218,120
|
|
|
|
211,039
|
|
|
|
183,736
|
|
|
Maintenance
|
|
|
61,899
|
|
|
|
52,040
|
|
|
|
57,030
|
|
|
Depreciation and amortization
|
|
|
141,585
|
|
|
|
124,098
|
|
|
|
118,841
|
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes (Note 10)
|
|
|
91,781
|
|
|
|
46,425
|
|
|
|
45,135
|
|
|
Other than income
|
|
|
28,118
|
|
|
|
25,535
|
|
|
|
25,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,772,809
|
|
|
|
1,654,440
|
|
|
|
1,567,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
351,272
|
|
|
|
228,827
|
|
|
|
216,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for other funds used during construction
|
|
|
11,755
|
|
|
|
18,683
|
|
|
|
4,230
|
|
|
Interest accrued on deferred energy
|
|
|
21,902
|
|
|
|
20,350
|
|
|
|
20,199
|
|
|
Disallowed merger costs
|
|
|
—
|
|
|
|
—
|
|
|
|
(3,961
|
)
|
|
Carrying
charge for Lenzie (Note 1)
|
|
|
33,440
|
|
|
|
—
|
|
|
|
—
|
|
|
Other income
|
|
|
16,992
|
|
|
|
25,626
|
|
|
|
22,844
|
|
|
Other expense
|
|
|
(8,480
|
)
|
|
|
(8,525
|
)
|
|
|
(6,665
|
)
|
|
Income taxes (Note 10)
|
|
|
(25,729
|
)
|
|
|
(17,570
|
)
|
|
|
(11,437
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,880
|
|
|
|
38,564
|
|
|
|
25,210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Before Interest Charges
|
|
|
401,152
|
|
|
|
267,391
|
|
|
|
241,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
171,188
|
|
|
|
159,106
|
|
|
|
152,764
|
|
|
Interest for Energy Suppliers (Note 13)
|
|
|
—
|
|
|
|
(14,825
|
)
|
|
|
(24,171
|
)
|
|
Other
|
|
|
17,038
|
|
|
|
13,563
|
|
|
|
14,533
|
|
|
Allowance for borrowed funds used during construction
|
|
|
(11,614
|
)
|
|
|
(23,187
|
)
|
|
|
(5,738
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
176,612
|
|
|
|
134,657
|
|
|
|
137,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
224,540
|
|
|
$
|
132,734
|
|
|
$
|
104,312
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
106
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
NET INCOME
|
|
$
|
224,540
|
|
|
$
|
132,734
|
|
|
$
|
104,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in market value of risk management
assets and liabilities as of December 31 (Net
of taxes of $785, and ($688) in 2005 and
2004, respectively)
|
|
|
—
|
|
|
|
(1,460
|
)
|
|
|
1,277
|
|
|
Minimum pension liability adjustment (Net of taxes
of ($520), $740 and ($1,205) in 2006, 2005 and
2004, respectively)
|
|
|
965
|
|
|
|
(2,769
|
)
|
|
|
2,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
965
|
|
|
|
(4,229
|
)
|
|
|
3,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
$
|
225,505
|
|
|
$
|
128,505
|
|
|
$
|
107,828
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements
107
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
and End of Year
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Paid-In Capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
1,808,848
|
|
|
|
1,576,794
|
|
|
|
1,377,106
|
|
|
Transfer of Goodwill
|
|
|
—
|
|
|
|
—
|
|
|
|
197,998
|
|
|
Revaluation of investment
|
|
|
—
|
|
|
|
119
|
|
|
|
1,690
|
|
|
Transfer of pension assets
|
|
|
33,521
|
|
|
|
—
|
|
|
|
—
|
|
|
Capital infusion from parent
|
|
|
200,000
|
|
|
|
231,935
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
2,042,369
|
|
|
|
1,808,848
|
|
|
|
1,576,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained Earnings (Deficit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
(43,422
|
)
|
|
|
(140,898
|
)
|
|
|
(199,837
|
)
|
|
Income for the year
|
|
|
224,540
|
|
|
|
132,734
|
|
|
|
104,312
|
|
|
Common stock dividends declared
|
|
|
(48,917
|
)
|
|
|
(35,258
|
)
|
|
|
(45,373
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
132,201
|
|
|
|
(43,422
|
)
|
|
|
(140,898
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
(3,338
|
)
|
|
|
891
|
|
|
|
(2,625
|
)
|
|
Change in market value of risk management assets and liabilities as of
December 31 (Net of taxes of $785 and ($688) in 2005 and 2004, respectively)
|
|
|
—
|
|
|
|
(1,460
|
)
|
|
|
1,277
|
|
|
Minimum pension liability adjustment (Net of taxes of ($520), $740 and ($1,205)
in 2006, 2005 and 2004, respectively)
|
|
|
965
|
|
|
|
(2,769
|
)
|
|
|
2,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
(2,373
|
)
|
|
|
(3,338
|
)
|
|
|
891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Common Shareholder’s Equity at End of Year
|
|
$
|
2,172,198
|
|
|
$
|
1,762,089
|
|
|
$
|
1,436,788
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
108
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
224,540
|
|
|
$
|
132,734
|
|
|
$
|
104,312
|
|
|
Non-cash items included in net loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
141,585
|
|
|
|
124,098
|
|
|
|
118,841
|
|
|
Deferred taxes and deferred investment tax credit
|
|
|
107,392
|
|
|
|
86,910
|
|
|
|
57,066
|
|
|
AFUDC
|
|
|
(11,755
|
)
|
|
|
(41,870
|
)
|
|
|
(9,969
|
)
|
|
Amortization of deferred energy costs
|
|
|
120,499
|
|
|
|
131,471
|
|
|
|
228,765
|
|
|
Deferred energy costs disallowed
|
|
|
—
|
|
|
|
—
|
|
|
|
1,586
|
|
|
Reinstatement of deferred energy
|
|
|
(178,825
|
)
|
|
|
—
|
|
|
|
|
|
|
Carrying charge on Lenzie plant
|
|
|
(33,440
|
)
|
|
|
—
|
|
|
|
|
|
|
Other
|
|
|
3,394
|
|
|
|
(7,433
|
)
|
|
|
(44,149
|
)
|
|
Changes in certain assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(35,191
|
)
|
|
|
(57,746
|
)
|
|
|
(7,247
|
)
|
|
Deferral of energy costs
|
|
|
(49,982
|
)
|
|
|
(186,338
|
)
|
|
|
(117,543
|
)
|
|
Deferral of energy costs — terminated suppliers
|
|
|
3,896
|
|
|
|
155,119
|
|
|
|
4,551
|
|
|
Materials, supplies and fuel
|
|
|
(13,919
|
)
|
|
|
(1,977
|
)
|
|
|
(3,782
|
)
|
|
Other current assets
|
|
|
5,421
|
|
|
|
14,434
|
|
|
|
14,522
|
|
|
Accounts payable
|
|
|
(2,431
|
)
|
|
|
30,855
|
|
|
|
10,350
|
|
|
Payment to terminating supplier
|
|
|
(37,410
|
)
|
|
|
—
|
|
|
|
(50,311
|
)
|
|
Proceeds from claim on terminating supplier
|
|
|
26,391
|
|
|
|
—
|
|
|
|
—
|
|
|
Other current liabilities
|
|
|
5,083
|
|
|
|
(107,575
|
)
|
|
|
10,504
|
|
|
Risk Management assets and liabilities
|
|
|
(2,219
|
)
|
|
|
(6,597
|
)
|
|
|
4,454
|
|
|
Other assets
|
|
|
(9,902
|
)
|
|
|
(9,950
|
)
|
|
|
6,168
|
|
|
Other liabilities
|
|
|
(2,946
|
)
|
|
|
(31,926
|
)
|
|
|
14,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash from Operating Activities
|
|
|
260,181
|
|
|
|
224,209
|
|
|
|
342,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS USED BY INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to utility plant
|
|
|
(670,441
|
)
|
|
|
(546,748
|
)
|
|
|
(482,484
|
)
|
|
AFUDC
|
|
|
11,755
|
|
|
|
41,870
|
|
|
|
9,969
|
|
|
Customer advances for construction
|
|
|
10,417
|
|
|
|
18,813
|
|
|
|
8,067
|
|
|
Contributions in aid of construction
|
|
|
21,241
|
|
|
|
8,544
|
|
|
|
10,703
|
|
|
Investments in subsidiaries and other property — net
|
|
|
7,363
|
|
|
|
1,875
|
|
|
|
5,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash used by Investing Activities
|
|
|
(619,665
|
)
|
|
|
(475,646
|
)
|
|
|
(448,341
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in restricted cash and investments
|
|
|
—
|
|
|
|
—
|
|
|
|
2,600
|
|
|
Proceeds from issuance of long-term debt
|
|
|
1,687,726
|
|
|
|
150,000
|
|
|
|
530,000
|
|
|
Retirement of long-term debt
|
|
|
(1,554,521
|
)
|
|
|
(238,486
|
)
|
|
|
(283,498
|
)
|
|
Additional investment by parent company
|
|
|
200,000
|
|
|
|
230,541
|
|
|
|
—
|
|
|
Dividends paid
|
|
|
(35,769
|
)
|
|
|
(35,260
|
)
|
|
|
(44,975
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash from Financing Activities
|
|
|
297,436
|
|
|
|
106,795
|
|
|
|
204,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(62,048
|
)
|
|
|
(144,642
|
)
|
|
|
98,426
|
|
|
Beginning Balance in Cash and Cash Equivalents
|
|
|
98,681
|
|
|
|
243,323
|
|
|
|
144,897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending Balance in Cash and Cash Equivalents
|
|
$
|
36,633
|
|
|
$
|
98,681
|
|
|
$
|
243,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosures of Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during period for:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
190,023
|
|
|
$
|
173,775
|
|
|
$
|
161,126
|
|
|
Income taxes
|
|
$
|
4,714
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfer of Regulatory Asset
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
197,998
|
|
The accompanying notes are an integral part of the financial statements
109
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Common Shareholder’s Equity:
|
|
|
|
|
|
|
|
|
|
Common stock, $1.00 par value, 1,000 shares authorized, issued and
Outstanding
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Other paid-in capital
|
|
|
2,042,369
|
|
|
|
1,808,848
|
|
|
Retained Earning (Deficit)
|
|
|
132,201
|
|
|
|
(43,422
|
)
|
|
Accumulated other comprehensive Income (Loss)
|
|
|
(2,373
|
)
|
|
|
(3,338
|
)
|
|
|
|
|
|
|
|
|
|
Total Common Shareholder’s Equity
|
|
|
2,172,198
|
|
|
|
1,762,089
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
Secured Debt
|
|
|
|
|
|
|
|
|
|
First Mortgage Bonds
|
|
|
|
|
|
|
|
|
|
8.50% Series Z due 2023
|
|
|
—
|
|
|
|
35,000
|
|
|
Debt Secured by First Mortgage Bonds
|
|
|
|
|
|
|
|
|
|
Revenue Bonds
|
|
|
|
|
|
|
|
|
|
6.60% Series 1992B due 2019
|
|
|
—
|
|
|
|
39,500
|
|
|
6.70% Series 1992A due 2022
|
|
|
—
|
|
|
|
105,000
|
|
|
7.20% Series 1992C due 2022
|
|
|
—
|
|
|
|
78,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
—
|
|
|
|
257,500
|
|
|
|
|
|
|
|
|
|
|
Debt Secured by General and Refunding Mortgage Securities
|
|
|
|
|
|
|
|
|
|
10.88% Series E due 2009
|
|
|
—
|
|
|
|
162,500
|
|
|
8.25% Series A due 2011
|
|
|
350,000
|
|
|
|
350,000
|
|
|
6.50% Series I due 2012
|
|
|
130,000
|
|
|
|
130,000
|
|
|
9.00% Series G due 2013
|
|
|
227,500
|
|
|
|
227,500
|
|
|
5.875% Series L due 2015
|
|
|
250,000
|
|
|
|
250,000
|
|
|
5.95% Series M due 2016
|
|
|
210,000
|
|
|
|
—
|
|
|
6.65% Series N due 2036
|
|
|
370,000
|
|
|
|
—
|
|
|
6.00% Series O due 2018
|
|
|
325,000
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
1,862,500
|
|
|
|
1,120,000
|
|
|
|
|
|
|
|
|
|
|
Variable Rate Notes
|
|
|
|
|
|
|
|
|
|
PCRB Series 2000B due 2009
|
|
|
15,000
|
|
|
|
15,000
|
|
|
IDRB Series 2000A due 2020
|
|
|
100,000
|
|
|
|
100,000
|
|
|
PCRB Series 2006 due 2036
|
|
|
39,500
|
|
|
|
—
|
|
|
PCRB Series 2006A due 2032
|
|
|
40,000
|
|
|
|
—
|
|
|
PCRB Series 2006B due 2039
|
|
|
13,000
|
|
|
|
—
|
|
|
Revolving Credit Facility
|
|
|
—
|
|
|
|
150,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
207,500
|
|
|
|
265,000
|
|
|
|
|
|
|
|
|
|
|
Unsecured Debt
|
|
|
|
|
|
|
|
|
|
Revenue Bonds
|
|
|
|
|
|
|
|
|
|
5.30% Series 1995D due 2011
|
|
|
14,000
|
|
|
|
14,000
|
|
|
5.35% Series 1995E due 2022
|
|
|
—
|
|
|
|
13,000
|
|
|
5.45% Series 1995D due 2023
|
|
|
6,300
|
|
|
|
6,300
|
|
|
5.50% Series 1995C due 2030
|
|
|
44,000
|
|
|
|
44,000
|
|
|
5.60% Series 1995A due 2030
|
|
|
76,750
|
|
|
|
76,750
|
|
|
5.90% Series 1995B due 2030
|
|
|
85,000
|
|
|
|
85,000
|
|
|
5.80% Series 1997B due 2032
|
|
|
—
|
|
|
|
20,000
|
|
|
5.90% Series 1997A due 2032
|
|
|
52,285
|
|
|
|
52,285
|
|
|
6.38% Series 1996 due 2036
|
|
|
—
|
|
|
|
20,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
278,335
|
|
|
|
331,335
|
|
|
|
|
|
|
|
|
|
|
Unamortized bond premium and discount, net
|
|
|
(12,757
|
)
|
|
|
(4,942
|
)
|
|
|
|
|
|
|
|
|
|
8.2% Junior Subordinated Debentures due 2037
|
|
|
—
|
|
|
|
122,548
|
|
|
7.75% Junior Subordinated Debentures due 2038
|
|
|
—
|
|
|
|
72,165
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
—
|
|
|
|
194,713
|
|
|
|
|
|
|
|
|
|
|
Obligations under capital leases
|
|
|
50,479
|
|
|
|
56,921
|
|
|
Current maturities and sinking fund requirements
|
|
|
(5,948
|
)
|
|
|
(6,509
|
)
|
|
Other, excluding current portion
|
|
|
30
|
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt
|
|
|
2,380,139
|
|
|
|
2,214,063
|
|
|
|
|
|
|
|
|
|
|
TOTAL CAPITALIZATION
|
|
$
|
4,552,337
|
|
|
$
|
3,976,152
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements
.
110
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Utility Plant at Original Cost:
|
|
|
|
|
|
|
|
|
|
Plant in service
|
|
$
|
2,766,672
|
|
|
$
|
2,695,427
|
|
|
Less accumulated provision for depreciation
|
|
|
1,057,165
|
|
|
|
1,041,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,709,507
|
|
|
|
1,654,320
|
|
|
Construction work-in-progress
|
|
|
227,500
|
|
|
|
66,799
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,937,007
|
|
|
|
1,721,119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments and other property, net (Note 4)
|
|
|
609
|
|
|
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
53,260
|
|
|
|
38,153
|
|
|
Restricted cash
|
|
|
—
|
|
|
|
14,871
|
|
|
Accounts receivable less allowance for uncollectible accounts:
|
|
|
|
|
|
|
|
|
|
2006-$6,732; 2005-$5,842
|
|
|
170,106
|
|
|
|
180,973
|
|
|
Accounts receivable, affiliated companies
|
|
|
—
|
|
|
|
40,278
|
|
|
Deferred energy costs — electric (Note 1)
|
|
|
38,956
|
|
|
|
67,342
|
|
|
Deferred energy costs — gas (Note 1)
|
|
|
—
|
|
|
|
5,825
|
|
|
Materials, supplies and fuel, at average cost
|
|
|
42,990
|
|
|
|
41,608
|
|
|
Risk management assets (Note 9)
|
|
|
10,927
|
|
|
|
27,822
|
|
|
Deposits and prepayments for energy
|
|
|
8,912
|
|
|
|
28,751
|
|
|
Other
|
|
|
11,184
|
|
|
|
9,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
336,335
|
|
|
|
455,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Charges and Other Assets:
|
|
|
|
|
|
|
|
|
|
Deferred energy costs — electric (Note 1)
|
|
|
22,697
|
|
|
|
40,725
|
|
|
Deferred energy costs — gas (Note 1)
|
|
|
—
|
|
|
|
845
|
|
|
Regulatory
tax asset (Note 10)
|
|
|
109,699
|
|
|
|
93,957
|
|
|
Regulatory
asset for pension plans (Note 1)
|
|
|
106,666
|
|
|
|
—
|
|
|
Other regulatory assets
|
|
|
228,255
|
|
|
|
205,578
|
|
|
Risk management assets (Note 9)
|
|
|
2,207
|
|
|
|
—
|
|
|
Risk management regulatory assets – net (Note 9)
|
|
|
39,025
|
|
|
|
—
|
|
|
Unamortized debt issuance costs
|
|
|
17,981
|
|
|
|
12,693
|
|
|
Other
|
|
|
7,356
|
|
|
|
15,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
533,886
|
|
|
|
369,170
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
2,807,837
|
|
|
$
|
2,546,301
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common shareholder’s equity
|
|
$
|
884,737
|
|
|
$
|
727,777
|
|
|
Preferred stock
|
|
|
—
|
|
|
|
50,000
|
|
|
Long-term debt
|
|
|
1,070,858
|
|
|
|
941,804
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,955,595
|
|
|
|
1,719,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
2,400
|
|
|
|
52,400
|
|
|
Accounts payable
|
|
|
89,743
|
|
|
|
56,661
|
|
|
Accounts payable, affiliated companies
|
|
|
11,769
|
|
|
|
—
|
|
|
Accrued interest
|
|
|
7,200
|
|
|
|
10,993
|
|
|
Dividends declared
|
|
|
6,736
|
|
|
|
968
|
|
|
Accrued salaries and benefits
|
|
|
15,209
|
|
|
|
14,032
|
|
|
Intercompany
income taxes payable (Note 10)
|
|
|
9,055
|
|
|
|
49,673
|
|
|
Deferred
income taxes (Note 10)
|
|
|
8,881
|
|
|
|
21,832
|
|
|
Risk management liabilities (Note 9)
|
|
|
38,391
|
|
|
|
6,455
|
|
|
Accrued taxes
|
|
|
3,407
|
|
|
|
3,541
|
|
|
Contract termination liabilities
|
|
|
—
|
|
|
|
39,216
|
|
|
Other current liabilities
|
|
|
12,125
|
|
|
|
10,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
204,916
|
|
|
|
266,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 13)
|
|
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes (Note 10)
|
|
|
278,515
|
|
|
|
244,244
|
|
|
Deferred investment tax credit
|
|
|
20,005
|
|
|
|
21,793
|
|
|
Regulatory
tax liability (Note 10)
|
|
|
20,624
|
|
|
|
23,156
|
|
|
Customer advances for construction
|
|
|
31,855
|
|
|
|
72,005
|
|
|
Accrued retirement benefits
|
|
|
124,254
|
|
|
|
40,269
|
|
|
Risk management liabilities (Note 9)
|
|
|
3,685
|
|
|
|
—
|
|
|
Risk management regulatory liability — net (Note 9)
|
|
|
—
|
|
|
|
15,015
|
|
|
Regulatory liabilities (Note 1)
|
|
|
130,605
|
|
|
|
110,911
|
|
|
Other
|
|
|
37,783
|
|
|
|
33,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
647,326
|
|
|
|
560,650
|
|
|
|
|
|
|
|
|
|
|
TOTAL CAPITALIZATION AND LIABILITIES
|
|
$
|
2,807,837
|
|
|
$
|
2,546,301
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
111
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
OPERATING REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,020,162
|
|
|
$
|
967,427
|
|
|
$
|
881,908
|
|
|
Gas
|
|
|
210,068
|
|
|
|
178,270
|
|
|
|
153,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,230,230
|
|
|
|
1,145,697
|
|
|
|
1,035,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power
|
|
|
344,590
|
|
|
|
352,098
|
|
|
|
304,955
|
|
|
Fuel for power generation
|
|
|
247,626
|
|
|
|
233,653
|
|
|
|
224,074
|
|
|
Gas purchased for resale
|
|
|
160,739
|
|
|
|
140,850
|
|
|
|
121,526
|
|
|
Deferral of energy costs — electric — net
|
|
|
47,043
|
|
|
|
8,110
|
|
|
|
7,060
|
|
|
Deferral of energy costs — gas — net
|
|
|
6,947
|
|
|
|
(749
|
)
|
|
|
(4,136
|
)
|
|
Other
|
|
|
141,350
|
|
|
|
131,901
|
|
|
|
128,091
|
|
|
Maintenance
|
|
|
31,273
|
|
|
|
26,690
|
|
|
|
21,877
|
|
|
Depreciation and amortization
|
|
|
87,279
|
|
|
|
90,569
|
|
|
|
86,806
|
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes
(Note 10)
|
|
|
23,570
|
|
|
|
26,038
|
|
|
|
14,978
|
|
|
Other than income
|
|
|
19,796
|
|
|
|
20,233
|
|
|
|
19,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,110,213
|
|
|
|
1,029,393
|
|
|
|
924,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
120,017
|
|
|
|
116,304
|
|
|
|
111,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for other funds used during construction
|
|
|
6,471
|
|
|
|
1,639
|
|
|
|
1,718
|
|
|
Interest accrued on deferred energy
|
|
|
5,996
|
|
|
|
7,092
|
|
|
|
5,133
|
|
|
Disallowed merger costs
|
|
|
—
|
|
|
|
—
|
|
|
|
(1,929
|
)
|
|
Plant costs disallowed
|
|
|
—
|
|
|
|
—
|
|
|
|
(47,092
|
)
|
|
Other income
|
|
|
9,412
|
|
|
|
5,940
|
|
|
|
3,406
|
|
|
Other expense
|
|
|
(8,422
|
)
|
|
|
(7,493
|
)
|
|
|
(5,726
|
)
|
|
Income
(taxes) / benefits (Note 10)
|
|
|
(4,259
|
)
|
|
|
(2,341
|
)
|
|
|
14,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,198
|
|
|
|
4,837
|
|
|
|
(29,837
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Before Interest Charges
|
|
|
129,215
|
|
|
|
121,141
|
|
|
|
81,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
71,869
|
|
|
|
69,240
|
|
|
|
71,312
|
|
|
Interest for Energy Suppliers (Note 13)
|
|
|
—
|
|
|
|
(2,396
|
)
|
|
|
(10,999
|
)
|
|
Other
|
|
|
5,142
|
|
|
|
3,727
|
|
|
|
5,367
|
|
|
Allowance for borrowed funds used during construction and
capitalized interest
|
|
|
(5,505
|
)
|
|
|
(1,504
|
)
|
|
|
(2,849
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71,506
|
|
|
|
69,067
|
|
|
|
62,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
57,709
|
|
|
|
52,074
|
|
|
|
18,577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend Requirements and premium on redemption of preferred stock
|
|
|
2,341
|
|
|
|
3,900
|
|
|
|
3,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings applicable to common stock
|
|
$
|
55,368
|
|
|
$
|
48,174
|
|
|
$
|
14,677
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
112
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
NET INCOME
|
|
$
|
57,709
|
|
|
$
|
52,074
|
|
|
$
|
18,577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in market value of risk management assets and
liabilities as of December 31 (net of taxes of $370
and ($323)
in 2005 and 2004, respectively)
|
|
|
—
|
|
|
|
(686
|
)
|
|
|
600
|
|
|
Minimum pension liability adjustment (net of taxes
of ($462), $632 and $65 in 2006, 2005 and 2004,
respectively)
|
|
|
861
|
|
|
|
(1,173
|
)
|
|
|
(123
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
861
|
|
|
|
(1,859
|
)
|
|
|
477
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
|
$
|
58,570
|
|
|
$
|
50,215
|
|
|
$
|
19,054
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements
113
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
and End of Year
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Paid-In Capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
810,103
|
|
|
|
810,103
|
|
|
|
713,633
|
|
|
Transfer of Goodwill (Note 19)
|
|
|
18,888
|
|
|
|
—
|
|
|
|
96,470
|
|
|
Transfer of pension assets
|
|
|
31,462
|
|
|
|
—
|
|
|
|
—
|
|
|
Capital infusion from parent
|
|
|
75,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
935,453
|
|
|
|
810,103
|
|
|
|
810,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained Earnings (Deficit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
(80,538
|
)
|
|
|
(104,779
|
)
|
|
|
(119,456
|
)
|
|
Income (Loss) from continuing operations before preferred dividends
|
|
|
57,709
|
|
|
|
52,074
|
|
|
|
18,577
|
|
|
Preferred stock redemption
|
|
|
(1,366
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Preferred stock dividends declared
|
|
|
(975
|
)
|
|
|
(3,900
|
)
|
|
|
(3,900
|
)
|
|
Common stock dividends declared
|
|
|
(24,619
|
)
|
|
|
(23,933
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
(49,789
|
)
|
|
|
(80,538
|
)
|
|
|
(104,779
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at Beginning of Year
|
|
|
(1,792
|
)
|
|
|
67
|
|
|
|
(410
|
)
|
|
Change in market value of risk management assets and liabilities as of
December 31 (Net of taxes of $370 and ($323) in 2005 and 2004,
respectively)
|
|
|
—
|
|
|
|
(686
|
)
|
|
|
600
|
|
|
Minimum pension liability adjustment (Net of taxes of ($462), $632 and $65
in 2006, 2005 and 2004, respectively)
|
|
|
861
|
|
|
|
(1,173
|
)
|
|
|
(123
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at End of Year
|
|
|
(931
|
)
|
|
|
(1,792
|
)
|
|
|
67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Common Shareholder’s Equity at End of Year
|
|
$
|
884,737
|
|
|
$
|
727,777
|
|
|
$
|
705,395
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
114
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended December 31
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
57,709
|
|
|
$
|
52,074
|
|
|
$
|
18,577
|
|
|
Non-cash items included in net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
87,279
|
|
|
|
90,569
|
|
|
|
86,806
|
|
|
Deferred taxes and deferred investment tax credit
|
|
|
(39,361
|
)
|
|
|
209
|
|
|
|
11,640
|
|
|
AFUDC
|
|
|
(6,471
|
)
|
|
|
(3,143
|
)
|
|
|
(4,567
|
)
|
|
Amortization of deferred energy costs — electric
|
|
|
46,322
|
|
|
|
56,750
|
|
|
|
36,653
|
|
|
Amortization of deferred energy costs — gas
|
|
|
6,234
|
|
|
|
1,446
|
|
|
|
3,241
|
|
|
Plant costs disallowed
|
|
|
—
|
|
|
|
—
|
|
|
|
47,092
|
|
|
Other
|
|
|
16,935
|
|
|
|
318
|
|
|
|
474
|
|
|
Changes in certain assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
36,171
|
|
|
|
(11,631
|
)
|
|
|
(19,677
|
)
|
|
Deferral of energy costs – electric
|
|
|
(4,755
|
)
|
|
|
(54,765
|
)
|
|
|
(34,598
|
)
|
|
Deferral of energy costs – gas
|
|
|
436
|
|
|
|
(2,519
|
)
|
|
|
(7,480
|
)
|
|
Deferral of energy costs – terminated suppliers
|
|
|
4,845
|
|
|
|
62,921
|
|
|
|
—
|
|
|
Materials, supplies and fuel
|
|
|
(1,382
|
)
|
|
|
(10,272
|
)
|
|
|
7,113
|
|
|
Other current assets
|
|
|
18,204
|
|
|
|
3,106
|
|
|
|
(10,086
|
)
|
|
Accounts payable
|
|
|
19,670
|
|
|
|
11,573
|
|
|
|
2,153
|
|
|
Payment to terminating supplier
|
|
|
(27,958
|
)
|
|
|
—
|
|
|
|
(10,818
|
)
|
|
Proceeds from claim on terminating supplier
|
|
|
14,974
|
|
|
|
—
|
|
|
|
—
|
|
|
Other current liabilities
|
|
|
(925
|
)
|
|
|
(48,603
|
)
|
|
|
5,567
|
|
|
Risk Management assets and liabilities
|
|
|
(3,731
|
)
|
|
|
(88
|
)
|
|
|
4,033
|
|
|
Other assets
|
|
|
(220
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Other liabilities
|
|
|
6,461
|
|
|
|
12,186
|
|
|
|
(8,844
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash from Operating Activities
|
|
|
230,437
|
|
|
|
160,131
|
|
|
|
127,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS (USED BY) INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to utility plant
|
|
|
(315,578
|
)
|
|
|
(139,646
|
)
|
|
|
(131,927
|
)
|
|
AFUDC
|
|
|
6,471
|
|
|
|
3,143
|
|
|
|
4,567
|
|
|
Customer advances for construction
|
|
|
6,931
|
|
|
|
8,545
|
|
|
|
8,130
|
|
|
Contributions in aid of construction
|
|
|
17,551
|
|
|
|
14,807
|
|
|
|
15,754
|
|
|
Investments in subsidiaries and other property — net
|
|
|
233
|
|
|
|
157
|
|
|
|
(82
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash used by Investing Activities
|
|
|
(284,392
|
)
|
|
|
(112,994
|
)
|
|
|
(103,558
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in short-term borrowings
|
|
|
—
|
|
|
|
—
|
|
|
|
(25,000
|
)
|
|
Change in restricted cash and investments
|
|
|
3,612
|
|
|
|
2,034
|
|
|
|
3,130
|
|
|
Proceeds from issuance of long-term debt
|
|
|
804,157
|
|
|
|
—
|
|
|
|
100,000
|
|
|
Retirement of long-term debt
|
|
|
(742,514
|
)
|
|
|
(2,504
|
)
|
|
|
(99,491
|
)
|
|
Redemption of preferred stock
|
|
|
(51,366
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Investment by parent company
|
|
|
75,000
|
|
|
|
—
|
|
|
|
—
|
|
|
Dividends paid
|
|
|
(19,827
|
)
|
|
|
(27,833
|
)
|
|
|
(3,900
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash from (used by) Financing Activities
|
|
|
69,062
|
|
|
|
(28,303
|
)
|
|
|
(25,261
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents:
|
|
|
15,107
|
|
|
|
18,834
|
|
|
|
(1,540
|
)
|
|
Beginning
Balance in Cash and Cash Equivalents:
|
|
|
38,153
|
|
|
|
19,319
|
|
|
|
20,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending Balance in Cash and Cash Equivalents
|
|
$
|
53,260
|
|
|
$
|
38,153
|
|
|
$
|
19,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosures of Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during period for:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
83,327
|
|
|
$
|
71,496
|
|
|
$
|
77,529
|
|
|
Income taxes
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfer of Regulatory Asset (Note 18)
|
|
$
|
18,888
|
|
|
$
|
—
|
|
|
$
|
96,470
|
|
The accompanying notes are an integral part of the financial statements
115
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Common Shareholder’s Equity:
|
|
|
|
|
|
|
|
|
|
Common stock, $3.75 par value, 20,000,000 shares
authorized, 1,000 shares issued and outstanding
|
|
$
|
4
|
|
|
$
|
4
|
|
|
Other paid-in capital
|
|
|
935,453
|
|
|
|
810,103
|
|
|
Retained Deficit
|
|
|
(49,789
|
)
|
|
|
(80,538
|
)
|
|
Accumulated other comprehensive Income (Loss)
|
|
|
(931
|
)
|
|
|
(1,792
|
)
|
|
|
|
|
|
|
|
|
|
Total Common Shareholder’s Equity
|
|
|
884,737
|
|
|
|
727,777
|
|
|
|
|
|
|
|
|
|
|
Cumulative Preferred Stock:
|
|
|
|
|
|
|
|
|
|
Not subject to mandatory redemption; 2,000,000 shares
outstanding; $25 stated value
|
|
|
—
|
|
|
|
50,000
|
|
|
|
|
|
|
|
|
|
|
SPPC Class A Series 1; $1.95 dividend
|
|
|
|
|
|
|
|
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
Secured Debt
|
|
|
|
|
|
|
|
|
|
Debt Secured by First Mortgage Bonds
|
|
|
|
|
|
|
|
|
|
Revenue Bonds
|
|
|
|
|
|
|
|
|
|
6.35% Series 1992B due 2012
|
|
|
—
|
|
|
|
1,000
|
|
|
6.55% Series 1987 due 2013
|
|
|
—
|
|
|
|
39,500
|
|
|
6.30% Series 1987 due 2014
|
|
|
—
|
|
|
|
45,000
|
|
|
6.65% Series 1987 due 2017
|
|
|
—
|
|
|
|
92,500
|
|
|
6.55% Series 1990 due 2020
|
|
|
—
|
|
|
|
20,000
|
|
|
6.30% Series 1992A due 2022
|
|
|
—
|
|
|
|
10,250
|
|
|
5.90% Series 1993A due 2023
|
|
|
—
|
|
|
|
9,800
|
|
|
5.90% Series 1993B due 2023
|
|
|
—
|
|
|
|
30,000
|
|
|
6.70% Series 1992 due 2032
|
|
|
—
|
|
|
|
21,200
|
|
|
Medium Term Notes
|
|
|
|
|
|
|
|
|
|
6.62% to 6.83% Series C due 2006
|
|
|
—
|
|
|
|
50,000
|
|
|
6.95% to 8.61% Series A due 2022
|
|
|
—
|
|
|
|
110,000
|
|
|
7.10% to 7.14% Series B due 2023
|
|
|
—
|
|
|
|
58,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
—
|
|
|
|
487,250
|
|
|
|
|
|
|
|
|
|
|
Debt Secured by General and Refunding Mortgage Securities
|
|
|
|
|
|
|
|
|
|
8.00% Series A due 2008
|
|
|
320,000
|
|
|
|
320,000
|
|
|
6.25% Series H due 2012
|
|
|
100,000
|
|
|
|
100,000
|
|
|
6.00% Series M due 2016
|
|
|
300,000
|
|
|
|
—
|
|
|
5.00% Series 2001 due 2036
|
|
|
80,000
|
|
|
|
80,000
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
800,000
|
|
|
|
500,000
|
|
|
|
|
|
|
|
|
|
|
Variable Rate Notes
|
|
|
|
|
|
|
|
|
|
PCRB Series 2006 due 2029
|
|
|
49,750
|
|
|
|
—
|
|
|
PCRB Series 2006A due 2031
|
|
|
58,700
|
|
|
|
—
|
|
|
PCRB Series 2006B due 2036
|
|
|
75,000
|
|
|
|
—
|
|
|
PCRB Series 2006C due 2036
|
|
|
84,800
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
268,250
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Debt
|
|
|
|
|
|
|
|
|
|
Unamortized bond premium and discount, net
|
|
|
(392
|
)
|
|
|
(666
|
)
|
|
Current maturities and sinking fund requirements
|
|
|
(2,400
|
)
|
|
|
(52,400
|
)
|
|
Other, excluding current portion
|
|
|
5,400
|
|
|
|
7,620
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt
|
|
|
1,070,858
|
|
|
|
941,804
|
|
|
|
|
|
|
|
|
|
|
TOTAL CAPITALIZATION
|
|
$
|
1,955,595
|
|
|
$
|
1,719,581
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
116
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies for both utility and non-utility operations are as
follows:
Basis of Presentation
The consolidated financial statements include the accounts of Sierra Pacific Resources (SPR)
and its wholly-owned subsidiaries, Nevada Power Company (NPC), Sierra Pacific Power Company (SPPC),
Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Lands of Sierra, Inc.
(LOS), Sierra Energy Company dba e ·three (e ·three), Sierra Pacific Energy Company (SPE), Sierra
Water Development Company (SWDC) and Sierra Gas Holding Company (SGHC). In 2004, certain operations
of SPC are discontinued operations and as such are reported separately in the financial statements.
NPC and SPPC are referred to together in this report as the Utilities. All significant intercompany
balances and intercompany transactions have been eliminated in consolidation.
The preparation of consolidated financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make estimates and
assumptions that affect the reported amounts of certain assets and liabilities. These estimates and
assumptions also affect the disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of certain revenues and expenses during the reporting
period. Actual results could differ from these estimates.
NPC is an operating public utility that provides electric service in Clark County in southern
Nevada. The assets of NPC represent approximately 68% of the consolidated assets of SPR at December
31, 2006. NPC provides electricity to approximately 807,000 customers in the communities of Las
Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air
Force Base. Service is also provided to the Department of Energy’s Nevada Test Site in Nye County.
The consolidated financial statements of SPR include NPC’s wholly-owned subsidiary, Nevada Electric
Investment Company (NEICO).
SPPC is an operating public utility that provides electric service in northern Nevada and
northeastern California. SPPC also provides natural gas service in the Reno/Sparks area of Nevada.
The assets of SPPC represent approximately 31% of the consolidated assets of SPR at December 31,
2006. SPPC provides electricity to approximately 361,000 customers in a 50,000 square mile service
area including 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. SPPC
also provides natural gas service in Nevada to approximately 146,000 customers in an area of about
600 square miles in the Reno and Sparks areas. The consolidated financial statements of SPPC
include the accounts of SPPC’s wholly-owned subsidiaries, Piñon Pine Corporation, Piñon Pine
Investment Company, GPSF-B, SPPC Funding LLC, and Sierra Pacific Power Capital I.
The Utilities’ accounts for electric operations and SPPC’s accounts for gas operations are
maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy
Regulatory Commission (FERC).
TGPC was a partner in a joint venture that developed, constructed, and operates a natural gas
pipeline serving the expanding gas market in the Reno area and certain northeastern California
markets. TGPC accounted for its joint venture interest under the equity method. In December 2006,
TGPC sold its partnership interest in the joint venture, see Note 4, Investment in Subsidiaries and
Other Property. SPC was formed in 1999 to provide telecommunications services using fiber optic
cable technology in both northern and southern Nevada.
Reclassifications
Certain reclassifications of prior year’s information have been made for comparative purposes
but have not affected previously reported results of operations or common shareholders’ equity.
Regulatory Accounting and Other Regulatory Assets
The Utilities’ rates are currently subject to the approval of the Public Utilities Commission
of Nevada (PUCN) and, in the case of SPPC, rates are also subject to the approval of the California
Public Utility Commission (CPUC) and are designed to recover the cost of providing generation,
transmission and distribution services. As a result, the Utilities qualify for the application of
Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain
Types of Regulation,” issued by the Financial Accounting Standards Board (FASB). This statement
recognizes that the rate actions of a regulator can provide reasonable assurance of the existence
of an asset and requires the deferral of incurred costs that would otherwise be charged to expense
where it is probable that future revenue will be provided to recover these costs. SFAS No. 71
prescribes the method to be used to record the financial transactions of a regulated entity. The
criteria for applying SFAS No. 71 include the following:
(i) rates are set by an independent third party regulator; (ii) regulated rates are designed to recover the specific costs of the regulated
products or
117
services; and (iii) it is reasonable to assume that rates are set at levels that
recovered costs can be charged to and collected from customers. Management periodically assesses
whether the requirements for application of SFAS No. 71 are satisfied.
In addition to the deferral of energy costs discussed below, items to which SPR and the
Utilities apply regulatory accounting are included in the tables below.
Regulatory assets represent incurred costs that have been deferred because it is probable they
will be recovered through future rates collected from customers. If at any time the incurred costs
no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities
generally represent obligations to make refunds to customers for previous collections, except for
cost of removal which represents the cost of removing future electric and gas assets. Management
regularly assesses whether the regulatory assets are probable of future recovery by considering
actions of regulators, current laws related to regulation, applicable regulatory environment
changes and the status of any current and pending or potential deregulation legislation.
Currently, the electric utility industry is predominantly regulated on a basis designed to
recover the cost of providing electric power to its retail and wholesale customers. If cost-based
regulation were to be discontinued in the industry for any reason, including competitive pressure
on the cost-based prices of electricity, profits could be reduced, and the Utilities might be
required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of
cost-based regulation could also require affected utilities to write off their associated
regulatory assets. Management cannot predict the potential impact, if any, of these competitive
forces on the Utilities’ future financial position and results of operations.
SIERRA PACIFIC RESOURCES
OTHER REGULATORY ASSETS AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AS OF DECEMBER 31, 2006
|
|
|
As of
|
|
|
|
|
Remaining
|
|
Receiving Regulatory Treatment
|
|
|
Pending
|
|
|
|
|
|
|
December
|
|
|
(dollars in thousands)
|
|
Amortization
|
|
Earning a
|
|
|
Not Earning
|
|
|
Regulatory
|
|
|
2006
|
|
|
31, 2005
|
|
|
DESCRIPTION
|
|
Period
|
|
Return(1)
|
|
|
a Return
|
|
|
Treatment
|
|
|
Total
|
|
|
Total
|
|
|
Regulatory Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on reacquired debt
|
|
Term of Related Debt
|
|
$
|
87,154
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
87,154
|
|
|
$
|
57,804
|
|
|
Lenzie
|
|
|
|
|
|
|
|
|
|
|
|
|
52,456
|
|
|
|
52,456
|
|
|
|
—
|
|
|
Mohave plant
and deferred costs
|
|
2026
|
|
|
21,582
|
|
|
|
—
|
|
|
|
(3,747
|
)
|
|
|
17,835
|
|
|
|
28,280
|
|
|
Clark Units 1-3
|
|
Various thru 2015
|
|
|
11,545
|
|
|
|
—
|
|
|
|
5,190
|
|
|
|
16,735
|
|
|
|
13,136
|
|
|
Piñon Pine
|
|
Various thru 2029
|
|
|
35,236
|
|
|
|
6,155
|
|
|
|
610
|
|
|
|
42,001
|
|
|
|
43,502
|
|
|
Plant assets
|
|
Various thru 2031
|
|
|
2,876
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,876
|
|
|
|
3,058
|
|
|
Asset Retirement Obligations
|
|
|
|
|
|
|
|
|
—
|
|
|
|
16,112
|
|
|
|
16,112
|
|
|
|
14,904
|
|
|
Nevada divestiture costs
|
|
2012
|
|
|
23,983
|
|
|
|
—
|
|
|
|
—
|
|
|
|
23,983
|
|
|
|
28,497
|
|
|
Merger transition/transaction costs
|
|
2016
|
|
|
—
|
|
|
|
28,916
|
|
|
|
—
|
|
|
|
28,916
|
|
|
|
32,569
|
|
|
Merger severance/relocation
|
|
2016
|
|
|
—
|
|
|
|
15,884
|
|
|
|
—
|
|
|
|
15,884
|
|
|
|
17,951
|
|
|
Merger goodwill
|
|
2046
|
|
|
—
|
|
|
|
293,199
|
|
|
|
—
|
|
|
|
293,199
|
|
|
|
281,739
|
|
|
California restructure costs
|
|
Thru 2009
|
|
|
979
|
|
|
|
880
|
|
|
|
—
|
|
|
|
1,859
|
|
|
|
2,459
|
|
|
Conservation programs
|
|
Thru 2012
|
|
|
2,574
|
|
|
|
—
|
|
|
|
50,701
|
|
|
|
53,275
|
|
|
|
24,144
|
|
|
Legal Costs
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
8,376
|
|
|
|
8,376
|
|
|
|
9,558
|
|
|
Other costs
|
|
Thru 2017
|
|
|
1,708
|
|
|
|
2,363
|
|
|
|
3,892
|
|
|
|
7,963
|
|
|
|
10,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
|
$
|
187,637
|
|
|
$
|
347,397
|
|
|
$
|
133,590
|
|
|
$
|
668,624
|
|
|
$
|
568,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pensions-SFAS 158
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
223,218
|
|
|
|
223,218
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regulatory assets
|
|
|
|
$
|
187,637
|
|
|
$
|
347,397
|
|
|
$
|
356,808
|
|
|
$
|
891,842
|
|
|
$
|
568,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of Removal
|
|
Various
|
|
$
|
283,641
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
283,641
|
|
|
$
|
246,960
|
|
|
Gain on Property Sales
|
|
Various thru 2008
|
|
|
4,531
|
|
|
|
—
|
|
|
|
—
|
|
|
|
4,531
|
|
|
|
11,285
|
|
|
SO2 Allowances
|
|
Various thru 2012
|
|
|
745
|
|
|
|
—
|
|
|
|
—
|
|
|
|
745
|
|
|
|
536
|
|
|
Gas Transportation Contract
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
17,542
|
|
|
Plant liability
|
|
2008
|
|
|
1,038
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,038
|
|
|
|
2,049
|
|
|
Impact Charge
|
|
2008
|
|
|
2,722
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,722
|
|
|
|
6,066
|
|
|
Depreciation-Customer Advances
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
8,775
|
|
|
|
8,775
|
|
|
|
—
|
|
|
Other
|
|
2008
|
|
|
—
|
|
|
|
326
|
|
|
|
125
|
|
|
|
451
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regulatory liabilities
|
|
|
|
$
|
292,677
|
|
|
$
|
326
|
|
|
$
|
8,900
|
|
|
$
|
301,903
|
|
|
$
|
284,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
118
NEVADA POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AS OF DECEMBER 31, 2006
|
|
|
As of
|
|
|
|
|
Remaining
|
|
Receiving Regulatory Treatment
|
|
|
Pending
|
|
|
|
|
|
|
December
|
|
|
(dollars in thousands)
|
|
Amortization
|
|
Earning a
|
|
|
Not Earning
|
|
|
Regulatory
|
|
|
2006
|
|
|
31, 2005
|
|
|
DESCRIPTION
|
|
Period
|
|
Return
(1)
|
|
|
a Return
|
|
|
Treatment
|
|
|
Total
|
|
|
Total
|
|
|
Regulatory Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on reacquired debt
|
|
Term of Related Debt
|
|
$
|
60,026
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
60,026
|
|
|
$
|
39,392
|
|
|
Lenzie
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
52,456
|
|
|
|
52,456
|
|
|
|
—
|
|
|
Mohave plant
and deferred costs
|
|
2026
|
|
|
21,582
|
|
|
|
—
|
|
|
|
(3,747
|
)
|
|
|
17,835
|
|
|
|
28,280
|
|
|
Clark Units 1-3
|
|
Various thru 2015
|
|
|
11,545
|
|
|
|
—
|
|
|
|
5,190
|
|
|
|
16,735
|
|
|
|
13,136
|
|
|
Asset Retirement Obligations
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
11,081
|
|
|
|
11,081
|
|
|
|
10,204
|
|
|
Nevada divestiture costs
|
|
2012
|
|
|
14,665
|
|
|
|
—
|
|
|
|
—
|
|
|
|
14,665
|
|
|
|
17,459
|
|
|
Merger transition/transaction costs
|
|
2014
|
|
|
—
|
|
|
|
20,237
|
|
|
|
—
|
|
|
|
20,237
|
|
|
|
22,838
|
|
|
Merger severance/relocation
|
|
2014
|
|
|
—
|
|
|
|
7,397
|
|
|
|
—
|
|
|
|
7,397
|
|
|
|
8,417
|
|
|
Merger Goodwill
|
|
2044
|
|
|
—
|
|
|
|
184,386
|
|
|
|
—
|
|
|
|
184,386
|
|
|
|
189,088
|
|
|
Conservation programs
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
42,636
|
|
|
|
42,636
|
|
|
|
19,048
|
|
|
Legal Costs
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
8,376
|
|
|
|
8,376
|
|
|
|
9,558
|
|
|
Other costs
|
|
2008
|
|
|
649
|
|
|
|
—
|
|
|
|
3,890
|
|
|
|
4,539
|
|
|
|
5,147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
|
$
|
108,467
|
|
|
$
|
212,020
|
|
|
$
|
119,882
|
|
|
$
|
440,369
|
|
|
$
|
362,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pensions-SFAS 158
|
|
|
|
|
—
|
|
|
|
—
|
|
|
$
|
113,646
|
|
|
$
|
113,646
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regulatory assets
|
|
|
|
$
|
108,467
|
|
|
$
|
212,020
|
|
|
$
|
233,528
|
|
|
$
|
554,015
|
|
|
$
|
362,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of Removal
|
|
Various
|
|
$
|
162,196
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
162,196
|
|
|
$
|
144,164
|
|
|
Gain on Property Sales
|
|
Various thru 2008
|
|
|
4,531
|
|
|
|
—
|
|
|
|
—
|
|
|
|
4,531
|
|
|
|
11,285
|
|
|
SO2 Allowances
|
|
Various thru 2012
|
|
|
745
|
|
|
|
—
|
|
|
|
—
|
|
|
|
745
|
|
|
|
536
|
|
|
Gas Transportation Contract
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
17,542
|
|
|
Depreciation-Customer Advances
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
3,701
|
|
|
|
3,701
|
|
|
|
—
|
|
|
Other
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
125
|
|
|
|
125
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regulatory liabilities
|
|
|
|
$
|
167,472
|
|
|
$
|
—
|
|
|
$
|
3,826
|
|
|
$
|
171,298
|
|
|
$
|
173,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
119
SIERRA PACIFIC POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AS OF DECEMBER 31, 2006
|
|
|
As of
|
|
|
|
|
Remaining
|
|
Receiving Regulatory Treatment
|
|
|
Pending
|
|
|
|
|
|
|
December
|
|
|
(dollars in thousands)
|
|
Amortization
|
|
Earning a
|
|
|
Not Earning
|
|
|
Regulatory
|
|
|
2006
|
|
|
31, 2005
|
|
|
DESCRIPTION
|
|
Period
|
|
Return (1)
|
|
|
a Return
|
|
|
Treatment
|
|
|
Total
|
|
|
Total
|
|
|
Regulatory assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on reacquired debt
|
|
Term of Related Debt
|
|
$
|
27,128
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
27,128
|
|
|
$
|
18,412
|
|
|
Piñon Pine
|
|
Various thru 2029
|
|
|
35,236
|
|
|
|
6,155
|
|
|
|
610
|
|
|
|
42,001
|
|
|
|
43,502
|
|
|
Plant assets
|
|
Various thru 2031
|
|
|
2,876
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,876
|
|
|
|
3,058
|
|
|
Asset Retirement Obligations
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
5,031
|
|
|
|
5,031
|
|
|
|
4,700
|
|
|
Nevada divestiture costs
|
|
2012
|
|
|
9,318
|
|
|
|
—
|
|
|
|
—
|
|
|
|
9,318
|
|
|
|
11,038
|
|
|
Merger transition/transaction costs
|
|
2016
|
|
|
—
|
|
|
|
8,679
|
|
|
|
—
|
|
|
|
8,679
|
|
|
|
9,731
|
|
|
Merger severance/relocation
|
|
2016
|
|
|
—
|
|
|
|
8,487
|
|
|
|
—
|
|
|
|
8,487
|
|
|
|
9,534
|
|
|
Merger goodwill
|
|
2046
|
|
|
—
|
|
|
|
108,813
|
|
|
|
—
|
|
|
|
108,813
|
|
|
|
92,651
|
|
|
California Restructure Costs
|
|
Thru 2009
|
|
|
979
|
|
|
|
880
|
|
|
|
—
|
|
|
|
1,859
|
|
|
|
2,459
|
|
|
Conservation Programs
|
|
Thru 2012
|
|
|
2,574
|
|
|
|
—
|
|
|
|
8,065
|
|
|
|
10,639
|
|
|
|
5,096
|
|
|
Other costs
|
|
Various thru 2017
|
|
|
1,059
|
|
|
|
2,363
|
|
|
|
2
|
|
|
|
3,424
|
|
|
|
5,397
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
|
$
|
79,170
|
|
|
$
|
135,377
|
|
|
$
|
13,708
|
|
|
$
|
228,255
|
|
|
$
|
205,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pensions-SFAS 158
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
106,666
|
|
|
|
106,666
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regulatory assets
|
|
|
|
$
|
79,170
|
|
|
$
|
135,377
|
|
|
$
|
120,374
|
|
|
$
|
334,921
|
|
|
$
|
205,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of Removal
|
|
Various
|
|
$
|
121,445
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
121,445
|
|
|
$
|
102,796
|
|
|
Plant liability
|
|
2008
|
|
|
1,038
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,038
|
|
|
|
2,049
|
|
|
Impact Charge
|
|
2008
|
|
|
2,722
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,722
|
|
|
|
6,066
|
|
|
Depreciation-Customer Advances
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
5,074
|
|
|
|
5,074
|
|
|
|
—
|
|
|
Other
|
|
2008
|
|
|
—
|
|
|
|
326
|
|
|
|
—
|
|
|
|
326
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regulatory liabilities
|
|
|
|
$
|
125,205
|
|
|
$
|
326
|
|
|
$
|
5,074
|
|
|
$
|
130,605
|
|
|
$
|
110,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Earning a return includes either a carrying charge on the asset /
liability balance, or a return as a component of weighted cost of
capital.
Deferral of Energy Costs
Nevada and California statutes permit regulated utilities to adopt deferred energy accounting
procedures. The intent of these procedures is to ease the effect on customers of fluctuations in
the cost of purchased gas, fuel, and purchased power.
In January 2000, in accordance with a PUCN order, SPPC resumed using deferred energy
accounting for its gas operations.
In April 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369
include, among others, a reinstatement of deferred energy accounting for fuel and purchased power
costs incurred by electric utilities. In accordance with the provisions of SFAS No. 71, the
Utilities implemented deferred energy accounting in March 2001, for their respective electric
operations. Under deferred energy accounting, to the extent actual fuel and purchased power costs
exceed fuel and purchased power costs recoverable through current rates that excess is not recorded
as a current expense on the statement of operations but rather is deferred and recorded as an asset
on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power
costs recoverable through current rates exceed actual fuel and purchased power costs. These excess
amounts are reflected in adjustments to rates and recorded as revenue or expense in future time
periods, subject to PUCN review.
Pursuant to AB 369, Nevada Revised Statute (NRS) requires the Utilities to file applications
to clear their respective deferred energy account balances at least every 12 months and provides
that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that
were the result of any practice or transaction that was undertaken, managed or performed
imprudently by the electric utility.” In reference to deferred energy accounting, NRS specifies
that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase
capacity, and to purchase energy. The Utilities also record and are eligible under the statute to
recover a carrying charge on such deferred balances.
120
The following deferred energy costs were included in the consolidated balance sheets as of the
dates shown (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
|
|
|
|
NPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPR
|
|
|
Description
|
|
|
|
Electric
|
|
|
Electric
|
|
|
Gas
|
|
|
Total
|
|
|
Unamortized balances approved for collection in current rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric — NPC Period 1
|
|
(Reinstatement of deferred energy)
(1)
|
|
$
|
178,825
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
178,825
|
|
|
Electric — NPC Period 3
|
|
(effective 4/05, 2 years)
|
|
|
(4,067
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(4,067
|
)
|
|
Electric — SPPC Period 3
|
|
(effective 6/05, 27 months)
|
|
|
—
|
|
|
|
6,034
|
|
|
|
—
|
|
|
|
6,034
|
|
|
Electric — NPC Period 4
|
|
(effective 4/05, 2 years)
|
|
|
6,347
|
|
|
|
—
|
|
|
|
—
|
|
|
|
6,347
|
|
|
Electric — NPC Period 5
|
|
(effective 8/06, 2 years)
|
|
|
153,720
|
|
|
|
—
|
|
|
|
—
|
|
|
|
153,720
|
|
|
Electric — SPPC Period 5
|
|
(effective 7/06, 2 years)
|
|
|
—
|
|
|
|
27,657
|
|
|
|
—
|
|
|
|
27,657
|
|
|
Nat. Gas — Per 6, LPG — Per 5
|
|
(effective 12/06, 1 year)
|
|
|
—
|
|
|
|
—
|
|
|
|
902
|
|
|
|
902
|
|
|
Balances pending PUCN approval
|
|
|
|
|
72,280
|
|
|
|
16,220
|
|
|
|
—
|
|
|
|
88,500
|
|
|
Cumulative CPUC Balance
|
|
|
|
|
—
|
|
|
|
9,956
|
|
|
|
—
|
|
|
|
9,956
|
|
|
Balances accrued since end of periods
submitted for PUCN approval
|
|
|
1,693
|
|
|
|
(14,479
|
)
|
|
|
(1,014
|
)
|
|
|
(13,800
|
)
|
|
Claims for terminated supply contracts
(2)
|
|
|
|
|
80,095
|
|
|
|
16,265
|
|
|
|
—
|
|
|
|
96,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
488,893
|
|
|
$
|
61,653
|
|
|
$
|
(112
|
)
(3)
|
|
$
|
550,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred energy costs — electric
|
|
|
|
$
|
129,304
|
|
|
$
|
38,956
|
|
|
$
|
—
|
|
|
$
|
168,260
|
|
|
Deferred Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred energy costs — electric
|
|
|
|
|
359,589
|
|
|
|
22,697
|
|
|
|
—
|
|
|
|
382,286
|
|
|
Current Liabilities Deferred energy costs — gas
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(112
|
)
|
|
|
(112
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
488,893
|
|
|
$
|
61,653
|
|
|
$
|
(112
|
)
|
|
$
|
550,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
|
|
|
|
NPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPR
|
|
|
Description
|
|
|
|
Electric
|
|
|
Electric
|
|
|
Gas
|
|
|
Total
|
|
|
Unamortized balances approved for collection in current rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric — NPC Period 2
|
|
(effective 5/03, 3 years)
|
|
$
|
(1,199
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,199
|
)
|
|
Electric — NPC Period 3
|
|
(effective 4/05, 2 years)
|
|
|
48,564
|
|
|
|
—
|
|
|
|
—
|
|
|
|
48,564
|
|
|
Electric — SPPC Period 3
|
|
(effective 6/05, 27 months)
|
|
|
—
|
|
|
|
23,208
|
|
|
|
—
|
|
|
|
23,208
|
|
|
Electric — NPC Period 4
|
|
(effective 4/05, 2 years)
|
|
|
71,490
|
|
|
|
—
|
|
|
|
—
|
|
|
|
71,490
|
|
|
Electric — SPPC Period 4
|
|
(effective 6/05, 1 year)
|
|
|
—
|
|
|
|
9,101
|
|
|
|
—
|
|
|
|
9,101
|
|
|
Natural Gas — Period 5
|
|
(effective 11/05, 1 year)
|
|
|
—
|
|
|
|
—
|
|
|
|
4,454
|
|
|
|
4,454
|
|
|
LPG Gas Period 3
|
|
(effective 11/04, 2 years)
|
|
|
—
|
|
|
|
—
|
|
|
|
36
|
|
|
|
36
|
|
|
LPG Gas Period 4
|
|
(effective 11/05, 1 year)
|
|
|
—
|
|
|
|
—
|
|
|
|
130
|
|
|
|
130
|
|
|
Balances pending PUCN approval
|
|
|
|
|
171,447
|
|
|
|
41,180
|
|
|
|
—
|
|
|
|
212,627
|
|
|
Cumulative CPUC Balance
|
|
|
|
|
—
|
|
|
|
6,699
|
|
|
|
—
|
|
|
|
6,699
|
|
|
Balances accrued since end of periods
submitted for PUCN approval
|
|
|
26,647
|
|
|
|
6,768
|
|
|
|
2,050
|
|
|
|
35,465
|
|
|
Claims for terminated supply contracts
(2)
|
|
|
|
|
83,993
|
|
|
|
21,111
|
|
|
|
—
|
|
|
|
105,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
400,942
|
|
|
$
|
108,067
|
|
|
$
|
6,670
|
|
|
$
|
515,679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred energy costs — electric
|
|
|
|
$
|
186,355
|
|
|
$
|
67,342
|
|
|
$
|
—
|
|
|
$
|
253,697
|
|
|
Deferred energy costs — gas
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
5,825
|
|
|
|
5,825
|
|
|
Deferred Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred energy costs — electric
|
|
|
|
|
214,587
|
|
|
|
40,725
|
|
|
|
—
|
|
|
|
255,312
|
|
|
Deferred energy costs — gas
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
845
|
|
|
|
845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
400,942
|
|
|
$
|
108,067
|
|
|
$
|
6,670
|
|
|
$
|
515,679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Amount not in current rates. As discussed in Note 13, Commitments and Contingencies,
Nevada Power Company 2001 Deferred Energy Case.
|
|
|
|
(2)
|
|
Amounts related to claims for terminated supply contracts are discussed in Note 13,
Commitments and Contingencies.
|
|
|
|
(3)
|
|
Credits represent over-collections, that is, the extent to which gas or fuel and
purchased power costs recovered through rates exceed actual gas or fuel and purchased
power costs
|
Carrying Charge on the Lenzie Generating Station
In 2004, the Public Utility Commission of Nevada (PUCN) granted NPC’s request to designate the
Chuck Lenzie Generating Station (“Lenzie”) as a critical facility and allowed a 2% enhanced Return
on Equity (ROE) to be applied to the Lenzie construction costs expended after acquisition. The
order allowed for an additional 1% enhanced ROE if the two Lenzie generating units were brought on
line early. In addition, the PUCN granted NPC’s request to begin accumulating a carrying charge as
a regulatory asset including the 3% enhanced ROE (collectively referred to as “carrying charges”),
until the plant is included in rates.
Units 1 and 2 were declared commercially operable in January 2006 and April 2006,
respectively, qualifying for the incentive ROE treatment. Based on the regulatory order, through
December 31, 2006, NPC has accumulated approximately $38.9 million in carrying charges; however,
$5.5 million of this amount has not been recorded for financial reporting purposes as it represents
equity carrying costs that are not recognized until collected through regulated rates. For
financial reporting purposes, through December 31, 2006, NPC recognized $33.4 million in other
income, and recorded a corresponding regulatory asset, which represents only the carrying charge
component associated with incurred debt costs. NPC has requested recovery of the $38.9 million in
carrying charges its 2006 general rate case filed in November 2006.
Utility Plant
The cost of additions, including betterments and replacements of units of property, are
charged to utility plant. When units of property are replaced, renewed or retired, their cost plus
removal or disposal costs, less salvage proceeds, are charged to accumulated depreciation. The
cost of current repairs and minor replacements are charged to maintenance expense when incurred,
with the exception of long term service agreements. These agreements may have annual payment
amounts for repairs which could vary over the life of the agreement between maintenance expense and
amounts to be capitalized. To ensure consistency in annual expense for
122
rate making purposes, the
amounts to be charged to maintenance expense are smoothed over the life of the contract, with an
offset to a regulatory asset account. Amounts prepaid for capital expenditure are recorded in a
prepaid asset account.
In addition to direct labor and material costs, certain other direct and indirect costs are
capitalized. The indirect construction overhead costs capitalized are based upon the following cost
components: the cost of time spent by administrative and supervision employees in planning and
directing construction; property taxes; employee benefits including such costs as pensions, post
retirement and post employment benefits, vacations and payroll taxes; and an allowance for funds
used during construction (AFUDC) which includes the cost of debt and equity capital associated with
construction activity.
Allowance for Funds Used During Construction
As part of the cost of constructing utility plant, the Utilities capitalize AFUDC. AFUDC
represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for
construction purposes in accordance with rules prescribed by the FERC and the PUCN. AFUDC is
capitalized in the same manner as construction labor and material costs, however, with an
offsetting credit to “other income” for the portion representing the cost of equity funds; and as a
reduction of interest charges for the portion representing borrowed funds. Recognition of this item
as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such
practices are intended to permit the Utility to earn a fair return on, and recover in rates charged
for utility services, all capital costs. This is accomplished by including such costs in the rate
base and in the provision for depreciation. NPC’s AFUDC rate used during 2006, 2005 and 2004 was
9.03%. SPPC’s AFUDC rates used during 2006, 2005 and 2004 were 8.97%, 8.96%, and 9.26%
respectively. As specified by the PUCN, certain projects may be assigned a lower or higher AFUDC
rate due to specific interest-rate financings directly associated with those projects.
Depreciation
Substantially all of the Utilities’ plant is subject to the ratemaking jurisdiction of the
PUCN or the FERC, and, in the case of SPPC, the CPUC. Depreciation expense is calculated using the
straight-line composite method over the estimated remaining service lives of the related
properties, which approximates the anticipated physical lives of these assets in most cases. NPC’s
depreciation provision for 2006, 2005, and 2004, as authorized by the PUCN and stated as a
percentage of the average depreciable property balances for those years, was approximately 3.15%,
3.15% and 3.05% respectively. SPPC’s depreciation provision for 2006, 2005 and 2004, as authorized
by the PUCN and stated as a percentage of the average cost of depreciable property, was
approximately 3.08%, 3.3% and 3.35% respectively.
Impairment of Long-Lived Assets
SPR, NPC and SPPC evaluate on an ongoing basis the recoverability of its assets for
impairments whenever events or changes in circumstance indicate that the carrying amount may not be
recoverable as described in SFAS No. 144 “Accounting for the Disposal or Impairment of Long-Lived
Assets.” (SFAS 144) See Note 17, Discontinued Operations and Disposal and Impairment of Long-Lived
Assets.
Accounting For Goodwill
SFAS No. 142 “Goodwill and Other Intangible Assets”, adopted by SPR, NPC and SPPC in January
2002, changed the accounting for goodwill from an amortization method to one requiring at least an
annual review for impairment. See Note 18, Goodwill and Other Merger Costs, for further
discussion.
Cash and Cash Equivalents
Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality
investments in money market funds.
Restricted Cash
At December 31, 2005, SPR had approximately $67.2 million of restricted cash in SPR’s
consolidated balance sheets, primarily consisting of an aggregate $49 million and $11 million in
cash collateral deposited by NPC and SPPC, respectively, into escrow in connection with the stay of
the Enron Judgment, as described in Note 13, Commitments and Contingencies. The cash collateral
plus interest was returned to the Utilities in January 2006.
123
Federal Income Taxes
SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes
are allocated based on SPR’s and each subsidiary’s respective taxable income or loss and investment
tax credits as if each subsidiary filed a separate return. SPR accounts for income taxes in
accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires recognition of
deferred tax liabilities and assets for the future tax consequences of events that have been
included in the consolidated financial statements or tax returns. Under this method, deferred tax
liabilities and assets are determined based on the difference between the financial statement and
tax basis of assets and liabilities using enacted tax rates in effect for the year in which the
differences are expected to reverse.
For regulatory purposes, the Utilities are authorized to provide for deferred taxes on the
difference between straight-line and accelerated tax depreciation on post-1969 utility plant
expansion property, deferred energy, and certain other differences between financial reporting and
taxable income, including those added by the Tax Reform Act of 1986 (TRA). In 1981, the Utilities
began providing for deferred taxes on the benefits of using the Accelerated Cost Recovery System
for all post-1980 property. In 1987, the TRA required the Utilities to begin providing deferred
taxes on the benefits derived from using the Modified Accelerated Cost Recovery System.
Deferred investment tax credits are being amortized over the estimated service lives of the
related properties. Investment tax credits are no longer available to the Utilities.
Revenues
Operating revenues include billed and unbilled utility revenues. The accrual for unbilled
revenues represents amounts owed to the Utilities for service provided to customers for which the
customers have not yet been billed. These unbilled amounts are also included in accounts
receivable.
Revenues related to the sale of energy are recorded based on meter reads, which occur on a
systematic basis throughout a month, rather than when the service is rendered or energy is
delivered. At the end of each month, the energy delivered to the customers from the date of their
last meter read to the end of the month is estimated and the corresponding unbilled revenues are
calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days
versus unbilled days, amount of energy procured and generated during that month, historical
customer class usage patterns and the Utilities’ current tariffs. Accounts receivable as of
December 31, 2006, include unbilled receivables of $92 million and $83 million for NPC and SPPC,
respectively. Accounts receivable as of December 31, 2005, include unbilled receivables of $80
million and $77 million for NPC and SPPC, respectively.
Asset Retirement Obligations
SFAS No. 143 “Accounting for Asset Retirement Obligations” provides accounting requirements
for the recognition and measurement of liabilities associated with the retirement of tangible
long-lived assets. Under the standard, these liabilities are recognized at fair value as incurred
and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the
liabilities due to the passage of time is classified as an operating expense. Retirement
obligations associated with long-lived assets included within the scope of SFAS No. 143 are those
for which a legal obligation exists under enacted laws, statutes written or oral contracts,
including obligations arising under the doctrine of promissory estoppel. SPR, NPC and SPPC adopted
SFAS No. 143 in January 2003.
Management’s methodology to assess its legal obligation included an inventory of assets by
company, system and components and a review of rights of way and easements, regulatory orders,
leases and federal, state, and local environmental laws. Management identified a legal obligation
to retire generation plant assets specified in land leases for NPC’s jointly-owned Navajo
generating station. The land on which the Navajo generating station resides is leased from the
Navajo Nation. Provisions of the lease require the lessees to remove the facilities upon request
of the Navajo Nation at the expiration of the leases.
In March, 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47
as clarification to SFAS No. 143. This Interpretation was effective no later than the end of
fiscal years ending after December 15, 2005 (December 31, 2005, for calendar-year enterprises). The
Interpretation clarified the term conditional retirement obligation as used in SFAS No. 143 as well
as when an entity would have sufficient information to reasonably estimate the fair value of an
asset retirement obligation.
Similar to the methodology used to assess legal obligations under SFAS 143, management
reviewed the inventory of assets by system and components, as well as rights of way and easements,
regulatory orders, leases and federal, state, and local environmental laws. Management has
determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with
Poly Chlorinated Biphenyl to have met the conditional asset retirement obligations of FIN 47.
124
As such, included in NPC’s and SPPC’s Other Liabilities accounts as of December 31, 2006 are
approximately $12.9 million and $5.3 million of ARO’s. As of December 31, 2005, the amounts were
approximately $12.1 million and $5.0 million. As the Utilities are subject to SFAS 71, accounting
treatment, the cumulative effect of these ARO’s were recorded in Other Regulatory Assets.
Cost of Removal
In addition to the legal asset retirement obligations booked under SFAS 143 and FIN 47, the
Utilities have accrued for the cost of removing non-legal retirement obligations of other electric
and gas assets, in accordance with accepted accounting practices. The amounts of such accruals
included in regulatory liabilities in 2006 are approximately $162 million and $121 million for NPC
and SPPC, respectively. In 2005, the amounts were approximately $144 million and $103 million.
Variable Interest Entities
In December 2003, the FASB issued a revised Interpretation No. 46, “Consolidation of Variable
Interest Entities” (FIN 46 (R)), which elaborates on Accounting Research Bulletin No. 51,
“Consolidated Financial Statements.” Among other requirements, FIN 46 (R) provides that a variable
interest entity be consolidated by the enterprise that is the primary beneficiary of the variable
interest entity. As of December 2003, SPR, NPC and SPPC adopted FIN 46 (R) for special purpose
entities. As of March 2004, SPR, NPC and SPPC adopted FIN 46 (R) for all variable interest
entities. To identify potential variable interests, management reviewed long term purchase power
contracts, including contracts with qualifying facilities (QFs), jointly owned facilities and
partnerships that are not consolidated. The Utilities identified seven QFs with long-term purchase
power contracts that are variable interests. However, the Utilities are not required at this time
to consolidate these QFs under the scope exception provided for in FIN 46 (R) due to the inability
to obtain information necessary to (1) determine whether the entity is a variable interest entity,
(2) determine whether the enterprise is the variable interest entity’s primary beneficiary, or (3)
perform the accounting required to consolidate the variable interest entity for which it is
determined to be the primary beneficiary. The Utilities have requested financial information from
these QFs but have not been successful in obtaining the information. The Utilities’ maximum
exposure to loss is limited to the cost of replacing these purchase power contracts if the QFs are
unable to deliver power. However, the Utilities believe their exposure is mitigated as they would
likely recover these costs through their deferred energy accounting mechanism. The Utilities have
not identified any other significant variable interests that require consolidation as of December
31, 2006.
Recent Pronouncements
SFAS 123 (R)
SPR adopted Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), “Share
Based Payment” (SFAS 123 R) in the first quarter of 2006 using the modified prospective method.
The Company had previously applied the provisions of Accounting Principles Board Opinion No. 25,
“Accounting for Stock Issued to Employees”, in accounting for its stock compensation plans and in
accordance with the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based
Compensation”, and the updated disclosure requirements set forth in SFAS No. 148, “Accounting for
Stock-Based Compensation-Transition and Disclosure”. Accordingly, no compensation cost had been
recognized previously.
SPR’s executive long-term incentive plan for key management employees permits the following
types of grants, separately or in combination: non-qualified and qualified stock options, stock
appreciation rights, restricted stock, performance units, performance shares and bonus stock. SPR
currently issues Performance Shares and Non Qualified Stock Options (NQSO) under this plan. In
addition, the Company also has an Employee Stock Purchase Plan (ESPP). Please refer to Note 12,
Stock Compensation Plans in the Notes to Consolidated Financial Statements for additional
information.
The adoption of SFAS 123 (R) did not have a material impact on the results of operations for
SPR.
SFAS 157
In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of
Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”). SFAS 157 addresses
the need for increased consistency in fair value measurements, defining fair value as the price
that would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date. It also establishes a framework for measuring
fair value and expands disclosure requirements. SFAS 157 is effective for SPR and the Utilities
beginning January 2008. SPR and the Utilities are currently evaluating the impact of the adoption
of SFAS 157 on their consolidated financial statements.
SFAS 158
In September 2006, the FASB issued SFAS 158 (“SFAS 158”) “Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106,
and 132-(R).”
125
SFAS 158 requires SPR and the Utilities to
recognize the overfunded or underfunded status of defined benefit postretirement plans in
their Consolidated Balance Sheets. An overfunded status would result in the recognition of an asset
and an underfunded status would result in the recognition of a liability. The adjustment to record
an asset or liability would result in a charge or credit to Accumulated Other Comprehensive
Income (AOCI), net of income tax effects. SFAS 158’s requirement to recognize the funded status of a benefit plan and new
disclosure requirements are effective as of the end of the fiscal year ending after December 15,
2006. The requirement to measure plan assets and benefit obligations as of the date of the
employer’s fiscal year-end statement of financial position is effective for fiscal years ending
after December 15, 2008. SPR and the Utilities have recorded amounts that otherwise would be
charged/credited to AOCI upon application of SFAS 158 as Other Regulatory Asset/Liabilities as they
believe these amounts will be recovered through rates similar to expenses related to SFAS 87
Employers’ Accounting for Pensions and SFAS 106 Employers’ Accounting for Other Postretirement
Expense other than Pensions. At December 31, 2006, SPR, NPC and
SPPC recorded $223.2 million,
$113.6 million and $106.7 million, respectively in Other Regulatory Assets.
The following tables provide details of the effects of implementing SFAS Statement No. 158
(dollars in thousands):
Pension
Incremental effect of adopting SFAS No. 158 as of December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to
|
|
|
Regulatory
|
|
|
|
|
|
|
|
Before
|
|
|
Adopt SFAS
|
|
|
Accounting
|
|
|
Balance after
|
|
|
|
|
Adoption
|
|
|
158
|
|
|
Adjustments
|
|
|
Adoption
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current Benefit Asset
|
|
$
|
55,921
|
|
|
$
|
(55,921
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Regulatory Asset
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
114,261
|
|
|
$
|
114,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Benefit Liability
|
|
$
|
—
|
|
|
$
|
(1,482
|
)
|
|
$
|
—
|
|
|
$
|
(1,482
|
)
|
|
Non-current Benefit Liability
|
|
$
|
(9,809
|
)
|
|
$
|
(99,454
|
)
|
|
$
|
—
|
|
|
$
|
(109,263
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS’ EQUITY
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive (Income) Loss
|
|
$
|
(46,112
|
)
|
|
$
|
156,857
|
|
|
$
|
(114,261
|
)
|
|
$
|
(3,516
|
)
|
Other Benefits
Incremental effect of adopting SFAS No. 158 as of December 31, 2006
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to
|
|
|
Regulatory
|
|
|
|
|
|
|
|
Before
|
|
|
Adopt SFAS
|
|
|
Accounting
|
|
|
Balance after
|
|
|
|
|
Adoption
|
|
|
158
|
|
|
Adjustment
|
|
|
Adoption
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current Benefit Asset
|
|
$
|
10,182
|
|
|
$
|
(10,182
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Regulatory Asset
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
108,956
|
|
|
$
|
108,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current Benefit Liability
|
|
$
|
(52,778
|
)
|
|
$
|
(56,178
|
)
|
|
$
|
—
|
|
|
$
|
(108,956
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive (Income) Loss
|
|
$
|
42,596
|
|
|
$
|
66,360
|
|
|
$
|
(108,956
|
)
|
|
$
|
—
|
|
At
December 31, 2006 SPR, NPC and SPPC recorded pension liabilities
of $110.7 million, $66.1 million and $34.9 million,
respectively, as a result of the adoption of SFAS No. 158. In
addition, SPR, NPC and SPPC also recorded liabilities of
$109.0 million, $21.5 million and $87.9 million,
respectively, for the other postretirement benefit plan as a result
of the adoption of SFAS No. 158. At December 31, 2005 SPR,
NPC and SPPC had pension liabilities of $16.4 million,
$4.0 million and $5.8 million, respectively, and additional
minimum liabilities of $7.9 million, $4.4 million and
$2.8 million, respectively, under the provisions of SFAS
No. 87 for the pension plan. SPR, NPC and SPPC had liabilities of $36.3 million, $14.1 million and
$31.7 million, respectively, at December 31, 2005 for the
other post retirement benefit plan.
FIN 46(R)-6
In April 2006, the FASB issued FASB Staff Position (“FSP”) FIN 46R-6,
Determining the
Variability to Be Considered in Applying FASB Interpretation No. 46(R).
This FSP addresses certain
implementation issues related to FASB Interpretation No. 46 (Revised December 2003),
Consolidation
of Variable Interest Entities.
Specifically, FSP FIN 46R-6 addresses how a reporting enterprise
should determine the variability to be considered in applying FIN 46R. The variability that is
considered in applying FIN 46R affects the determination of (a) whether an entity is a variable
interest entity (“VIE”), (b) which interests are “variable interests” in the entity, and (c) which
party, if any, is the primary beneficiary of the VIE. That variability affects any calculation of
expected losses and expected residual returns, if such a calculation is necessary. SPR and the
Utilities are required to apply the guidance in this FSP prospectively to all entities (including
newly created entities) and to all entities previously required to be analyzed under FIN 46R when a
“reconsideration event” has occurred, beginning July 2006. SPR and the Utilities will evaluate the
impact of this Staff Position at the time any such “reconsideration event” occurs, and for any new
entities.
FIN 48
In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”) “Accounting for
Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109”, to clarify certain
aspects of accounting for uncertain tax positions, including issues related to the recognition and
measurement of those tax positions. This interpretation is effective for fiscal years beginning
after December 15, 2006. SPR and the Utilities are in the process of evaluating the impact FIN 48
will have on their consolidated financial statements.
SAB 108
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting
Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements (SAB 108), to address diversity in practice in
quantifying financial statement misstatements. SAB 108 requires that SPR and the Utilities quantify
misstatements based on their impact on each of its financial statements and related disclosures.
SAB 108 is effective as of December 31, 2006, allowing a one-time transitional cumulative effect
adjustment to retained earnings as of January 2006 for errors that were not previously deemed
material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have an
effect on the consolidated financial statements of SPR or the Utilities.
126
NOTE 2. SEGMENT INFORMATION
SPR’s Utilities operate three business segments (as defined by SFAS 131, “Disclosure about
Segments of an Enterprise and Related Information”); which are NPC electric, SPPC electric and SPPC
natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC,
northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by
SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the
quantitative threshold for separate disclosure.
Operational information of the different business segments is set forth below based on the
nature of products and services offered. SPR evaluates performance based on several factors, of
which, the primary financial measure is business segment operating income. The accounting policies
of the business segments are the same as those described in Note 1, Summary of Significant
Accounting Policies. Inter-segment revenues are not material (dollars in thousands).
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPC
|
|
SPPC
|
|
Total
|
|
|
|
|
|
|
|
|
|
Reconciling
|
|
|
|
December 31, 2006
|
|
Electric
|
|
Electric
|
|
Electric
|
|
Gas
|
|
All Other
|
|
Eliminations
|
|
Consolidated
|
|
Operating Revenues
|
|
$
|
2,124,081
|
|
|
$
|
1,020,162
|
|
|
|
3,144,243
|
|
|
$
|
210,068
|
|
|
$
|
1,639
|
|
|
|
—
|
|
|
$
|
3,355,950
|
|
|
Operating income
|
|
|
351,272
|
|
|
|
108,908
|
|
|
|
460,180
|
|
|
|
11,109
|
|
|
|
17,508
|
|
|
|
—
|
|
|
|
488,797
|
|
|
Operating income taxes
|
|
|
91,781
|
|
|
|
20,020
|
|
|
|
111,801
|
|
|
|
3,550
|
|
|
|
(23,780
|
)
|
|
|
—
|
|
|
|
91,571
|
|
|
Depreciation
|
|
|
141,585
|
|
|
|
79,580
|
|
|
|
221,165
|
|
|
|
7,699
|
|
|
|
11
|
|
|
|
—
|
|
|
|
228,875
|
|
|
Interest expense on long term debt
|
|
|
171,188
|
|
|
|
66,416
|
|
|
|
237,604
|
|
|
|
5,453
|
|
|
|
51,431
|
|
|
|
—
|
|
|
|
294,488
|
|
|
Assets
|
|
|
5,987,515
|
|
|
|
2,476,483
|
|
|
|
8,463,998
|
|
|
|
275,294
|
|
|
|
36,724
|
|
|
|
56,060
|
|
|
|
8,832,076
|
|
|
Capital expenditures
|
|
|
670,441
|
|
|
|
282,641
|
|
|
|
953,082
|
|
|
|
32,937
|
|
|
|
—
|
|
|
|
—
|
|
|
|
986,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPC
|
|
|
SPPC
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
Reconciling
|
|
|
|
|
|
December 31, 2005
|
|
Electric
|
|
|
Electric
|
|
|
Electric
|
|
|
Gas
|
|
|
All Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
Operating Revenues
|
|
$
|
1,883,267
|
|
|
$
|
967,427
|
|
|
$
|
2,850,694
|
|
|
$
|
178,270
|
|
|
$
|
1,278
|
|
|
|
—
|
|
|
$
|
3,030,242
|
|
|
Operating income
|
|
|
228,827
|
|
|
|
107,213
|
|
|
|
336,040
|
|
|
|
9,091
|
|
|
|
13,547
|
|
|
|
—
|
|
|
|
358,678
|
|
|
Operating income taxes
|
|
|
46,425
|
|
|
|
24,209
|
|
|
|
70,634
|
|
|
|
1,829
|
|
|
|
(33,278
|
)
|
|
|
—
|
|
|
|
39,185
|
|
|
Depreciation
|
|
|
124,098
|
|
|
|
82,676
|
|
|
|
206,774
|
|
|
|
7,893
|
|
|
|
(5
|
)
|
|
|
—
|
|
|
|
214,662
|
|
|
Interest expense on long term debt
|
|
|
159,106
|
|
|
|
63,040
|
|
|
|
222,146
|
|
|
|
6,200
|
|
|
|
74,322
|
|
|
|
—
|
|
|
|
302,668
|
|
|
Assets
|
|
|
5,173,921
|
|
|
|
2,218,938
|
|
|
|
7,392,859
|
|
|
|
245,707
|
|
|
|
150,324
|
|
|
|
81,656
|
|
|
|
7,870,546
|
|
|
Capital expenditures
|
|
|
546,748
|
|
|
|
121,767
|
|
|
|
668,515
|
|
|
|
17,879
|
|
|
|
—
|
|
|
|
—
|
|
|
|
686,394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPC
|
|
|
SPPC
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
Reconciling
|
|
|
|
|
|
December 31, 2004
|
|
Electric
|
|
|
Electric
|
|
|
Electric
|
|
|
Gas
|
|
|
All Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
Operating Revenues
|
|
$
|
1,784,092
|
|
|
$
|
881,908
|
|
|
$
|
2,666,000
|
|
|
$
|
153,752
|
|
|
$
|
5,044
|
|
|
|
—
|
|
|
$
|
2,824,796
|
|
|
Operating income
|
|
|
216,490
|
|
|
|
103,513
|
|
|
|
320,003
|
|
|
|
7,732
|
|
|
|
6,123
|
|
|
|
—
|
|
|
|
333,858
|
|
|
Operating income taxes
|
|
|
45,135
|
|
|
|
12,740
|
|
|
|
57,875
|
|
|
|
2,238
|
|
|
|
(37,374
|
)
|
|
|
—
|
|
|
|
22,739
|
|
|
Depreciation
|
|
|
118,841
|
|
|
|
79,298
|
|
|
|
198,139
|
|
|
|
7,508
|
|
|
|
275
|
|
|
|
—
|
|
|
|
205,922
|
|
|
Interest expense on long term debt
|
|
|
152,764
|
|
|
|
64,729
|
|
|
|
217,493
|
|
|
|
6,583
|
|
|
|
89,229
|
|
|
|
—
|
|
|
|
313,305
|
|
|
Assets
|
|
|
4,883,540
|
|
|
|
2,226,949
|
|
|
|
7,110,489
|
|
|
|
232,092
|
|
|
|
120,607
|
|
|
|
65,279
|
|
|
|
7,528,467
|
|
|
Capital expenditures
|
|
|
482,484
|
|
|
|
117,329
|
|
|
|
599,813
|
|
|
|
14,598
|
|
|
|
—
|
|
|
|
—
|
|
|
|
614,411
|
|
The reconciliation of segment assets at December 31, 2006, 2005, and 2004 to the
consolidated total includes the following unallocated amounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Cash
|
|
$
|
53,260
|
|
|
$
|
53,024
|
|
|
$
|
35,783
|
|
|
Other regulatory assets
|
|
|
—
|
|
|
|
19,265
|
|
|
|
21,124
|
|
|
Deferred charges-other
|
|
|
2,800
|
|
|
|
9,367
|
|
|
|
8,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
56,060
|
|
|
$
|
81,656
|
|
|
$
|
65,279
|
|
|
|
|
|
|
|
|
|
|
|
|
127
NOTE 3. REGULATORY ACTIONS
The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC,
with respect to rates, standards of service, siting of and necessity for, generation and certain
transmission facilities, accounting, issuance of securities and other matters with respect to
electric distribution and transmission operations. NPC and SPPC submit Integrated Resource Plans
(IRPs) to the PUCN for approval.
Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily
by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service,
interconnection, accounting and other matters in connection with the Utilities’ sale of electricity
for resale and interstate transmission. The FERC also has jurisdiction over the natural gas
pipeline companies from which the Utilities take service.
As a result of regulation, many of the fundamental business decisions of the Utilities, as
well as the rate of return they are permitted to earn on their utility assets, are subject to the
approval of governmental agencies.
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 United States
Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and
Clark County Department of Air Quality and Environmental Management (DAQEM) administer regulations
involving air quality, water pollution, solid, hazardous and toxic waste. SPR’s Board of Directors
has a comprehensive environmental policy and separate board committee that oversees NPC, SPPC, and
SPR’s corporate performance and achievements related to the environment.
Deferred Energy Accounting
The Utilities began using deferred energy accounting for their respective electric operations
in March 2001. The intent of deferred energy accounting is to ease the effect of fluctuations in
the cost of purchased power and fuel.
Nevada Matters
Nevada Power Company
2006 General Rate Case
In November 2006, NPC filed its statutorily required electric general rate case. This filing
request authorization to:
|
|
•
|
|
Increase annual general revenues by $172.4 million which is approximately an 8% increase
|
|
|
|
|
•
|
|
Set the Return on Equity and Rate of Return at 11.40% and 9.41%, respectively
|
|
|
|
|
•
|
|
Recover 100% of the amortization of the 1999 NPC/SPPC merger costs rather than the
80% recovery that is currently in general rates
|
|
|
|
|
•
|
|
Implement the PUCN’s previous orders regarding incentive ratemaking for the Chuck Lenzie Generating Station
|
|
|
|
|
•
|
|
Implement new depreciation rates
|
Hearings are scheduled to take place in late March and early April of 2007 with rates expected
to be effective on or before June 1, 2007.
In February 2007, NPC submitted its certification filing which lowered the requested ROR to
9.39% and the general revenues increase was lowered to $156.4 million, representing an overall rate
increase of 7.4%.
2007 Deferred Energy Rate Case and BTER Update
In January 2007, NPC filed an electric DEAA rate case and BTER update application with the
PUCN. The application seeks recovery of $75 million of deferred fuel and purchased power costs and
requested to reset NPC’s going forward BTER to reflect anticipated changes in future energy costs.
This application requests a 1.6% decrease in overall rates.
2007 Western Energy Crisis Rate Case
In January 2007, NPC filed an application to recover $83.6 million over four years in deferred
legal and settlement costs incurred to resolve claims associated with power supply contracts
terminated during the western energy crisis. This application requests an overall rate increase of
less than 1%.
In February 2007, NPC entered into a stipulation, with the parties to the case, to recover the
$83.6 million plus carrying charges over a 3-year period beginning June 1, 2007. This stipulation
is expressly conditioned upon the PUCN’s acceptance of the
128
concurrently filed stipulation related
to NPC’s 2001 Deferred Energy Case, discussed below. If the PUCN does not accept both
stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all
rights to litigate. The PUCN has yet to issue an order on the stipulation.
2006 Deferred Energy Rate Case and BTER Update
In January 2006, NPC filed a DEAA rate case with the PUCN seeking recovery of deferred fuel
and purchased power costs accumulated between October 1, 2004 and November 30, 2005, and to
increase its going forward Base Tariff Energy Rate (BTER) to reflect anticipated changes in future
energy costs. NPC requested a one year amortization period to recover the deferred balance.
NPC requested that the BTER increase become effective on May 1, 2006. The BTER change
represented an 8% increase for the average customer and is expected to generate $138 million of new
revenues for fuel and power purchases.
NPC requested authorization to begin a one year recovery of the $171.5 million deferred
balance in August 2006. The requested DEAA adjustment represents an additional rate increase of
approximately 9.3%.
In April 2006, the PUCN approved an agreement among the interveners and NPC, which, effective
May 1, 2006, set NPC’s BTER rates such that an estimated $112 million (revised by June 2006 DEAA
agreement – see below) of new revenues would be collected for fuel and power purchases in addition
to the start of an $8.4 million collection related to a previous DEAA rate case. Combined, the
approximately $120 million increase represented an overall average rate increase of approximately
6.5%.
In the Deferred Energy portion of the case, NPC had requested authorization to recover $171.5
million of previously incurred purchased fuel and power costs over a one year period. In June
2006, the PUCN approved a negotiated settlement, which specified (1) a reduction of $1.6 million to
the BTER approved in April 2006 based on an updated projection of costs and (2) granted NPC full
recovery of the $171.5 million of deferred costs during a two year period beginning August 2006.
However, the $171.5 million was reduced by a $16.5 million payment previously received by NPC in
connection with the Lenzie acquisition. Under this agreement, the DEAA rate changes required to
asymmetrically recover the deferred balance are scheduled to be implemented during a two year
period such that they will be offset by the expiration of previously approved DEAA rates. As a
result, no rate increase was required.
2005 BTER Update
In June 2005, NPC filed a request to increase its BTER to reflect forecasted energy costs.
NPC expected the request would increase revenue by $66.9 million for the 12 month period October 1,
2005 to September 30, 2006 and more closely correlate fuel and purchased power revenues with fuel
and purchased power costs. In September 2005, the PUCN issued an order approving the BTER rate
changes requested in NPC’s filing.
2004 Deferred Energy Rate Case
In November 2004, NPC filed an application with the PUCN seeking recovery of deferred fuel and
purchased power costs accumulated between October 1, 2003 and September 30, 2004. The application
sought to establish a rate to collect accumulated fuel and purchased power costs of $116 million,
with a carrying charge. The application requested that the 2004 DEAA recovery begin with the
expiration of the 2002 DEAA recovery, which was expected to occur in May 2006 and for the 2004 DEAA
recovery period to be 22 months.
The application also requested an increase to NPC’s BTER.
In concert with this 2004 DEAA filing, NPC filed a petition with the PUCN requesting that
other pending DEAA rate changes be synchronized to change in April 2005 in order to stabilize rates
and reduce the number of rate changes. In December 2004, the PUCN issued an order approving a
stipulation reached by all parties that allows NPC to defer previously approved DEAA rate changes
until April 2005 coincident with the DEAA rate change that will result from the 2004 DEAA case.
The combined effect of the requested synchronization of multiple rate changes (going forward
BTER increase, 2001 DEAA expiration, and 2003 DEAA initiation) resulted in a request for an overall
rate decrease of 2.4%.
In February 2005, a stipulation of the parties was filed with the PUCN resolving all issues in
the case. The stipulation provided for an overall decrease of 0.6% in total rates with no
disallowances. The PUCN approved the stipulation in total in March 2005.
2003 Deferred Energy Rate Case
In November 2003, NPC filed an application with the PUCN seeking recovery of deferred fuel and
purchased power costs accumulated between October 1, 2002 and September 30, 2003, as required by
law. The application sought to establish a rate to collect accumulated fuel and purchased power
costs of $93 million. In March 2004, the PUCN granted approval for NPC to increase
129
its going
forward energy rate as filed, approved recovery for $89 million of its deferred balance, denied $4
million, and denied NPC’s request for a tax gross-up on the equity portion of carrying charges. Of
the $4 million disallowed, $1.6 million was charged to income
in the current period as the remaining amount had no impact on earnings or was charged to
income in prior periods. The PUCN ordered the change in going forward rates to take effect April
2004 and delayed the implementation of the deferred energy balance recovery until January 2005 when
recovery of the 2001 deferred balance was expected to have been completed.
In December 2004, the PUCN issued an order approving a stipulation reached by all parties that
allows NPC to defer the 2003 DEAA rate change until April 2005, which will be coincident with the
DEAA rate change that will result from the 2004 DEAA case.
2002 Deferred Energy Rate Case
In November 2002, NPC filed an application with the PUCN seeking repayment for purchased fuel
and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law.
The application sought to establish a rate to collect accumulated purchased fuel and power costs of
$195.7 million, together with a carrying charge, over a period of not more than three years. The
application also requested a reduction to the going-forward rate for energy, reflecting reduced
wholesale energy costs. The combined effect of these two adjustments resulted in a request for an
overall rate reduction of approximately 6.3%.
The decision on this case was issued in May 2003, and authorized the following:
|
|
•
|
|
recovery of $147.6 million, with a carrying charge, and a $48.1 million disallowance;
|
|
|
|
|
•
|
|
a three-year amortization of the balance commencing on May 19, 2003;
|
|
|
|
|
•
|
|
a reduction in the Base Tariff Energy Rate (BTER) to an effective
non-residential rate of $0.04322 per kWh, and an effective residential rate of
$0.04186 per kWh.
|
The new rates went into effect in May 2003.
The BCP filed a Petition that challenged the recovery of all costs with the District Court of
Clark County, Nevada, for Judicial Review of the PUCN Order in August 2003, against PUCN, Case No.
A471928. In September 2003, the PUCN filed its answer to the BCP Petition. The PUCN response cites
a number of affirmative defenses to the allegations contained in the BCP petition and asks that the
court dismiss the BCP petition. The BCP filed its opening brief in January 2004 and responding
briefs were filed in March 2004. The court has not yet ruled on this matter.
2001 Deferred Energy Rate Case
In November 2001, NPC filed an application with the PUCN seeking repayment for purchased fuel
and power costs accumulated between March 1, 2001, and September 30, 2001, as required by law. The
application sought to establish a rate to repay accumulated purchased fuel and power costs of $922
million and spread the recovery of the deferred costs, together with a carrying charge, over a
period of not more than three years.
In March 2002, the PUCN issued its decision on the deferred energy application, allowing NPC
to recover $478 million over a three-year period, but disallowing $434 million of deferred
purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in
carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from
October 2001 through February 2002. The order stated that the disallowance was based on alleged
imprudence in incurring the disallowed costs. NPC and the BCP both sought individual review of the
PUCN Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision.
Both NPC and the BCP filed Notices of Appeal to the Nevada Supreme Court.
In July 2006, the Supreme Court of Nevada ruled NPC is allowed to recover approximately $180
million of the deferred energy costs and directed the District Court to remand the issue back to
the PUCN to determine the rate schedule that will be used to recover this amount. In all other
respects, the Nevada Supreme Court affirmed the District Court’s decision on the PUCN disallowance.
In 2006, as a result of the Nevada Supreme Court decision, NPC recorded approximately $180
million, before tax, of the previously deferred energy costs in its Income Statements as
“Reinstatement of Deferred Energy.” NPC is unable to predict the terms of the rate schedule that
the PUCN will provide for recovery of this amount.
In February 2007, NPC entered into a stipulation where NPC shall be authorized to recover in
rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges.
This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed
stipulation related to the Western Energy Crisis, discussed above. If the PUCN does not accept
both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all
rights to litigate. The PUCN has yet to issue an order on the stipulation.
130
Sierra Pacific Power Company
2005 Electric and Gas General Rate Cases
In October 2005, SPPC filed a Gas general rate case along with its statutorily required
Electric general rate case. SPPC’s last Gas general rate case was filed in 1992 and the last
electric general rate case was filed in 2003. The following items are requested in the filings:
|
|
•
|
|
Electric general revenue increase: $27 million or 3.4% effective May 1, 2006
|
|
|
|
|
•
|
|
Gas general revenue increase: $8.3 million or 5.4%, effective May 1, 2006
|
|
|
|
|
•
|
|
Electric Return on Equity and Rate of Return: 11.4% and 9.27% respectively
|
|
|
|
|
•
|
|
Gas Return on Equity and Rate of Return: 11.4% and 8.29% respectively
|
|
|
|
|
•
|
|
Approval to continue to recover an allocated amount of the 1999 NPC/SPPC merger costs from Electric customers
|
|
|
|
|
•
|
|
Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs from Gas customers
|
|
|
|
|
•
|
|
New depreciation rates for Gas and Electric facilities
|
SPPC submitted its certification filing for cost of capital and depreciation rates in December
2005 and its revenue requirements and rate design certification filing in January 2006. These
filings did not change the requested ROE, ROR or depreciation rates, but did adjust the requested
electric revenue increase to $3.2 million.
In January 2006, the interveners filed direct testimony addressing return on equity, overall
rate of return and depreciation rates. The PUCN Staff has recommended a 10.28% ROE for Electric
and Gas operations, an 8.97% Electric ROR, an 8.06% Gas ROR and depreciation rates that would
result in decreased depreciation expenses. Other interveners are recommending ROE’s ranging from
9.1% to 10.9%, Electric ROR’s from 8.35% to 9.08% and Gas ROR’s from 7.52% to 8.10%. The other
interveners have also suggested depreciation rates lower than SPPC’s filing.
In February 2006, the interveners filed direct testimony addressing overall revenue
requirements, including the effects of their ROE, ROR and depreciation rate recommendations. The
PUCN Staff recommended a $15 million decrease to current electric revenues and a $3.6 million
increase to gas revenues. The Bureau of Consumer Protection (BCP) recommended a $32 million
reduction to current electric revenues and a $0.6 million increase to current gas revenues. The
Nevada Resort Association recommended a $12 million decrease to current electric revenues.
In April 2006, the PUCN issued its order to change electric and gas general rates. Although
the order differed from SPPC’s requested filing, the changes did not require material adjustments
to net income for the six months ended June 30, 2006. The PUCN vote resulted in the following
significant items:
|
|
•
|
|
Electric general revenue decrease: approximately $14 million annually or 1.5% effective May 1, 2006.
|
|
|
|
|
•
|
|
Gas general revenue increase: $4.5 million annually or 2.3%, effective May 1, 2006.
|
|
|
|
|
•
|
|
Electric Return on Equity and Rate of Return: 10.6% and 8.96% respectively.
|
|
|
|
|
•
|
|
Gas Return on Equity and Rate of Return: 10.6% and 7.98% respectively.
|
|
|
|
|
•
|
|
Approval to continue recovery of SPPC’s allocated amount of the 1999 NPC/SPPC
merger costs and goodwill from Electric customers.
|
|
|
|
|
•
|
|
Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Gas customers.
|
|
|
|
|
•
|
|
New depreciation rates for Gas and Electric facilities.
|
|
|
|
|
•
|
|
Deferred recovery of legal expenses related to the Enron purchased power contract litigation
|
2003 Electric General Rate Case
SPPC filed its biennial general rate case in December 2003, as required by law. SPPC
requested an $87 million increase in the annual revenue requirement for general rates. In April
2004, SPPC, the Staff of the PUCN and other interveners in SPPC’s 2003 general rate case negotiated
a settlement agreement that resolved most of the issues in the revenue requirement and cost of
capital portions of SPPC’s case. The agreement, which has been approved by the PUCN, includes the
following provisions:
|
|
•
|
|
SPPC was allowed to recover a $40 million increase in annual rates.
|
131
|
|
•
|
|
SPPC was allowed a Return on Equity (ROE) of 10.25%, and an overall Rate of Return
(ROR) of 9.26%, an improvement over SPPC’s previous ROE and ROR, which were 10.17% and
8.61%, respectively. SPPC had sought an ROE of 12.4% and ROR of 10.03%.
|
|
|
|
|
•
|
|
The agreement accepted SPPC’s requested accounting treatment as filed in its
application for purposes of recording revenues, expenses and assets with the following
exception. Accounting issues common to SPPC’s general rate case and NPC’s general rate
case that was decided by the PUCN in March 2004, in Docket No. 03-10001, are treated as
set forth in the PUCN’s Order on NPC’s general rate case, except for merger costs. The
accounting treatment for merger costs and goodwill established in the NPC decision will
apply to the recovery of these costs by SPPC, except that SPPC will include in rates
100% of the costs as filed until recovery is reset by the PUCN in SPPC’s next general
rate application.
|
|
|
|
|
•
|
|
Required SPPC to file a set of recommended quality of service and customer service
measurements to be used in future general rate case proceedings. In July 2004, SPPC and
NPC jointly filed with the PUCN their recommended quality of service and customer
service measurements.
|
The parties also reached a stipulated agreement that resolved the rate design issues in the
case.
Investments in the Piñon Pine generating facility were not addressed by the stipulation. SPPC
had sought recovery of its investment of approximately $96 million ($90 million associated with the
Nevada jurisdiction) for costs associated with this facility over an extended period (between 10
and 25 years). The recovery of these costs would be in addition to the $40 million annual increase
provided for by the stipulation agreement.
In May 2004, the PUCN issued an order accepting the two stipulations, discussed above, and
responding to SPPC’s request for recovery of the Piñon investments. The PUCN permitted recovery of
approximately $37 million (Nevada jurisdictional) of the costs plus a carrying charge to be
amortized over 25 years and approximately $11 million (Nevada jurisdictional) of costs without a
carrying charge to be amortized over 10 years. The PUCN order granted a $46.7 million increase to
SPPC’s general revenues.
As a result of the PUCN order, SPPC evaluated the Piñon Pine generating facility for
impairment under the provisions of SFAS No. 90, “Regulated Enterprises—Accounting for Abandonments
and Disallowances of Plant Costs”. As a result of this evaluation, SPPC recognized an impairment
loss of approximately $47 million in the second quarter of 2004. The impairment loss recognized
consists of disallowed costs of approximately $43 million and an additional $4 million loss because
the PUCN did not permit a carrying charge on $11 million of the costs to be recovered.
SPPC filed a petition for judicial review of the PUCN’s Piñon Decision in the Second Judicial
District Court of Nevada in June 2004. The petition is based on existing resource planning
statutes and regulations as they apply to the Piñon project. The Piñon project was approved by the
PUCN in SPPC’s 1992 Integrated Resource Plan as presented.
In January 2006, the court vacated the PUCN’s disallowance in Sierra Pacific’s 2003 General
Rate Case and remanded the case back to the PUCN for further review whether the costs were justly
and reasonably incurred. In March 2006, the PUCN appealed the Order to the Nevada Supreme Court
(the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court.
In June 2006, the District Court granted PUCN’s motion to stay the Order. In July 2006, the Supreme
Court issued an order questioning the finality of the District Court’s decision and thus whether it
has jurisdiction over the appeal and invited the parties to brief this matter. The BCP and PUCN
responded in early August, 2006. The Supreme Court dismissed the appeal in September 2006.
Requests for rehearing were denied in late December 2006, and in January 2007 the matter was
remitted back to the District Court, which, consistent with its January 2006 order, will remand the
matter back to the PUCN for further review. A procedural schedule for this review has not yet been
established.
132
2006 Electric Deferred Energy Rate Case and BTER Update
In December 2006, SPPC filed an electric DEAA rate case and BTER update application with the
PUCN. The application seeks recovery of $18.7 million of deferred fuel and purchased power costs
and requested to reset SPPC’s going forward BTER to reflect anticipated changes in future energy
costs. This application requests a 0.86% decrease in overall rates.
2006 Western Energy Crisis Rate Case
In December 2006, SPPC filed an application to recover $22.6 million over four years in
deferred legal and settlement costs incurred to resolve claims associated with power supply
contracts terminated during the western energy crisis. This application requests an overall rate
increase of less than 1%.
In February 2007, SPPC entered into a stipulation where SPPC replaces its request to implement
rates on July 1, 2007 with a request to establish a regulatory asset to recover the costs. SPPC
further requests authority to recover carrying charges on the regulatory asset. SPPC may request
authority to begin recovering the regulatory asset established by the PUCN in a future application
to change rates. The parties to the stipulation have requested that the PUCN issue an order by
September 30, 2007.
December 2005 Deferred Energy Rate Cases and Base Tariff Energy Rate Updates
In December 2005, SPPC filed an electric deferred energy rate case application with the PUCN.
The application sought to establish a rate to collect accumulated fuel and purchased power costs of
$46.7 million from the December 2004 to September 2005 deferral period and $17.5 million from the
previously approved unamortized deferrals, for a total $64.2 million. In June 2006, the
PUCN approved a negotiated settlement, which granted SPPC full recovery of the deferred costs
during a two year period beginning July 2006. Under this agreement, the DEAA rate changes required
to asymmetrically recover the $46.7 million deferred balance are scheduled to be implemented such
that they will be offset by the expiration of previously approved DEAA rates. As a result, no rate
increase was required
The application also requested an increase to the BTER. In April 2006, the PUCN issued an
order authorizing SPPC to increase its BTER on May 1, 2006, such that SPPC expects to collect $31
million in new revenues for purchased power. The change represented a 3.5% increase to customer
rates.
July 2005 Electric Base Tariff Energy Rate Update
In July 2005, SPPC filed a request to increase its BTER to reflect forecasted energy costs.
The request was expected to increase revenue by $32.3 million for the period October 1, 2005 to
September 30, 2006 and was intended to more closely correlate fuel and purchased power revenues
with fuel and purchased power costs.
In October 2005, the PUCN voted to approve a new electric BTER effective November 1, 2005.
The new rate represented a 7.3% overall electric rate increase and was expected to produce $64
million additional revenues during the following 12 months.
January 2005 Electric Deferred Energy Rate Case Filing
In January, 2005, SPPC filed an application with the PUCN seeking recovery of deferred fuel
and purchased power costs accumulated between December 2003 and November 2004, as required by law.
The application also requested an increase to the BTER or going-forward energy rate.
The PUCN issued its order in May, 2005 granting $27.1 million deferred expense recovery ($27.7
million requested less $0.6 million), modifying the amortization period from the two years
requested to one year and approving a BTER rate based on the historical costs methodology as
provided for in the Nevada Administrative Code. The overall rate increase was 5.15%.
SPPC 2004 Deferred Energy Case
In January, 2004, SPPC filed an application with the PUCN, as required by law, seeking to
clear deferred balances of approximately $42 million for purchased fuel and power costs accumulated
between December 1, 2002, and November 30, 2003.
In July, 2004, the PUCN ruled on the deferred energy case, and approved a full recovery of the
fuel and purchased power costs. The PUCN order delayed the start of the deferred balance recovery
until April 2005, which corresponds with the expected repayment of previous deferred balances. The
PUCN also ordered SPPC to implement a higher BTER rate (the rate paid for going forward energy
purchases) than that requested by SPPC. The higher BTER rate represents an overall increase of 4.4%
in electric rates for SPPC and became effective in July 2004.
133
2006 Natural Gas and Propane Deferred Energy Rate Case and BTER Update
In May, 2006, SPPC’s gas distribution operation filed applications with the PUCN seeking
recovery of deferred natural gas and propane costs accumulated between April 1, 2005 and March 31,
2006. The applications sought to establish a new natural gas DEAA rate to recover $2.5 million of
deferred natural gas costs and a new propane DEAA rate to recover $120 thousand of deferred propane
costs. SPPC also requested authorization to increase going forward natural gas and propane BTER’s
to reflect forecasted gas costs.
In October, 2006, the PUCN approved negotiated natural gas and propane settlements which
consolidated the deferred natural gas and propane balances for collection from all gas customers
and reduced the combined balance to $1.1 million. The agreements transferred approximately $1.4
million to other deferral periods and $.1 million to expense accounts. The agreements called for
the cost recovery to occur over a 12 month period beginning in December, 2006.
The negotiated going forward natural gas rate is expected to recover an additional $1.3
million in revenue, which is a decrease from the originally requested $24.5 million. The decrease
reflects more current natural gas price expectations.
These settlements, combined with the expiration of a previous natural gas DEAA rate will cause
natural gas customer rates to decrease by 2.5% and cause propane customer rates to increase by 3.3
%.
2005 Gas Deferred Energy Rate Case and Base Tariff Energy Rate Update
In May, 2005, SPPC filed a gas deferred energy rate case requesting recovery of $6.9 million
of deferred energy costs. The filing requested a two-year amortization of the deferred energy
balance which represents a 3.2% average increase for all customers.
In July, 2005, SPPC filed a proposed gas BTER, which represented an average increase of 19.5%
for all customer classes. The estimated BTER revenue would not change SPPC’s operating income.
In October, 2005, the PUCN voted to approve recovery of $6.9 million of deferred energy costs
with a one year amortization and set a new gas BTER rate, both effective in November, 2005. The
new BTER was expected to produce $34.1 million additional revenues during a 12 month period. The
combined increases represented a 25.3% overall gas rate increase.
SPPC Natural Gas Distribution 2004 Annual Purchased Gas Cost Adjustment
In May, 2004, SPPC filed its annual application for Purchased Gas Cost Adjustment for its
natural gas local distribution company. In the application, SPPC asked for an increase of $0.09456
per therm to its Base Purchased Gas Rate to recover its expected going forward gas costs. SPPC also
requested that $0.02857 per therm be added to the Balancing Account Adjustment (BAA) rate to
amortize an approximate $3.9 million balance of deferred gas costs, which were accumulated during
the accounting period. Combined with the simultaneous expiration of past BAA charges, the new BAA
rate would be $0.03869 per therm less than the current BAA rate. Overall, this request would result
in a rate increase of approximately 5%.
The parties agreed to a stipulation, which recommended the PUCN approve the requested rates
and the PUCN issued an order approving the rate increase in November, 2004.
California Electric Matters (Sierra Pacific Power Company)
2006 Energy Cost Adjustment Clause Rate Case
In April, 2006, SPPC filed with the CPUC to reset its “balancing” rate to recover a forecasted
deferred energy cost balance and to increase its “offset” rate for going-forward fuel and power
purchases. The requested increase in the balancing rate is expected to result in $1.1 million
additional revenue and the requested increase in the offset rate is expected to collect an
additional $10.1 million. The total request represents an $11.2 million annual revenue increase or
a 16.5% average increase to customer rates.
In October, 2006, the CPUC authorized SPPC’s request as filed.
2005 General Rate Case
In June, 2005, SPPC filed a California general rate case requesting $8.1 million of new
revenue from approximately 40,000 California customers. The request represents a 12.7% average
increase. SPPC requested that the new rates become effective in January, 2006.
134
In August, 2006, the CPUC approved a settlement agreement, which beginning in September, 2006,
allowed SPPC to collect an estimated $4.1 million of additional general revenues from its
California customers.
2004 Energy Cost Adjustment Clause Rate Case
In May, 2004, SPPC filed its annual Energy Cost Adjustment Clause (ECAC) in California. The
filing updated its estimated fuel and purchase power costs for its California customers and sought
to recover or refund any deferred amounts projected through September, 2004. The filing requests
$8.3 million or a 14.8% overall increase consisting of $3.9 million increase in the base rate and
$4.4 million for the projected balance. In November, 2004, the CPUC approved SPPC’s adjusted
request and the increase became effective in December, 2004.
Rate Stabilization Plan
In June 2001, SPPC filed with the CPUC a Rate Stabilization Plan, which included two phases.
Phase One, which was also filed in June 2001, was an emergency electric rate increase of $10.2
million annually or 26%. In July 2002, the CPUC approved the requested 2-cent per kilowatt-hour
surcharge, subject to refund and interest pending the outcome of Phase Two. Rates went into effect
July 2002.
Phase Two of the Rate Stabilization Plan was filed with the CPUC in April 2002, and included a
general rate case and requested the CPUC to reinstate the ECAC, which would allow SPPC to file for
annual rate adjustments to reflect its actual costs for wholesale energy supplies. This request was
for an additional overall increase in revenues of 17.1%, or $8.9 million annually.
In January 2004, the CPUC issued Decision No. 04-01-027, which approved a settlement agreement
that included an increase of $3.02 million or 5.8%, adopted a rate design methodology and
re-instituted the ECAC mechanism. The rate increase was effective January 16, 2004.
FERC Matters
Sierra Pacific Power Company 2004 Transmission Rate Case
In October 2004, the Utilities filed with the FERC revised rates for transmission service
offered by SPPC under Docket No. ER05-14. The purpose of the filing was to update rates to reflect
recent transmission additions and to improve rate design. The participants in the proceeding filed
a Settlement Agreement with the FERC, which was certified by the Settlement Judge. In May 2005,
the FERC issued an order approving the negotiated settlement.
Nevada Power Company 2003 Transmission Rate Case
In September 2003, the Utilities filed with the FERC revised rates for transmission service
offered by NPC under Docket No. ER03-1328. The purpose of the filing was to update rates to
reflect recent transmission additions and to improve rate design. In November 2003, FERC accepted
the revised tariff sheets, made rates effective in November 2003, subject to refund, and
established hearing procedures. The active participants in the proceeding reached a settlement in
principle of all issues. The Certification of Uncontested Offer of Settlement was issued in June
2004. The FERC issued an Order approving the uncontested settlement in July 2004. Refunds were
issued within thirty days as required by FERC.
Nevada Power Company
Based on the FERC’s orders to date, NPC believes the recalculated energy prices for NPC sales
to the California Independent System Operator (CAISO) and the bankrupt California Power Exchange
(CALPX) would result in an approximate $19 million refund. The FERC has also allowed for energy
sellers to provide cost justification in the event the recalculated energy prices fall below
sellers’ costs. NPC’s developed and filed a cost based filing, which justified a $6 million
reduction to the estimated refunds resulting in a $13 million refund.
The CAISO and CALPX currently owe NPC approximately $19 million for power delivered during the
same timeframe and a $13 million refund would reduce the amount owed to Nevada Power to $6 million.
NPC previously recorded a reserve against the $19 million receivable in 2001.
Sierra Pacific Power Company
Based on the FERC’s orders to date, SPPC believes the recalculated energy prices for sales to
the CAISO and CALPX during the October 2, 2000 to June 20, 2001 timeframe would result in a $4
million refund.
135
The CAISO and CALPX currently owe SPPC approximately $1 million for power delivered during the
same timeframe and SPPC recorded a reserve against the $1 million receivable in 2001. In 2004,
SPPC recorded an additional $3 million liability for this item.
NOTE 4. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY
Investments in subsidiaries and other property consisted of (dollars in thousands):
Sierra Pacific Resources
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Investment in Tuscarora Gas Transmission
Company (1)
|
|
$
|
590
|
|
|
$
|
30,898
|
|
|
Cash Value-Life Insurance
|
|
|
12,891
|
|
|
|
13,281
|
|
|
Non-utility property of NEICO
|
|
|
5,101
|
|
|
|
4,948
|
|
|
NVPCT-I & NVPCT-III
|
|
|
—
|
|
|
|
5,841
|
|
|
Decatur/Gilmore/Cheyenne/Centennial
|
|
|
4,184
|
|
|
|
5,179
|
|
|
Other non-utility Property
|
|
|
11,559
|
|
|
|
22,624
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
34,325
|
|
|
$
|
82,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Tuscarora Gas Pipeline Company (TGPC), which is wholly owned by SPR, sold its interest in
Tuscarora Gas Transmission Company during December 2006 for approximately $100 million. The
gain on the sale of the investment was approximately $40.9 million after taxes.
|
Nevada Power
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Cash Value-Life Insurance
|
|
$
|
12,891
|
|
|
$
|
13,281
|
|
|
Non-utility property of NEICO
|
|
|
5,101
|
|
|
|
4,948
|
|
|
NVPCT–I & NVPCT-III
|
|
|
—
|
|
|
|
5,841
|
|
|
Decatur/Gilmore/Cheyenne/Centennial
|
|
|
4,184
|
|
|
|
5,179
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
22,176
|
|
|
$
|
29,249
|
|
|
|
|
|
|
|
|
|
Sierra Pacific Power
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Non-utility Property
|
|
$
|
609
|
|
|
$
|
842
|
|
|
|
|
|
|
|
|
|
NOTE 5. JOINTLY OWNED FACILITIES
At December 31, 2006, NPC and SPPC owned the following undivided interests in jointly owned
electric utility facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction
|
|
|
|
|
%
|
|
|
Plant
|
|
|
Accumulated
|
|
|
Net Plant
|
|
|
Work in
|
|
|
Joint Facility
|
|
Owned
|
|
|
in Service
|
|
|
Depreciation
|
|
|
in Service
|
|
|
Progress
|
|
|
NPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Navajo Facility
|
|
|
11.3
|
|
|
$
|
240,350
|
|
|
$
|
127,507
|
|
|
$
|
112,843
|
|
|
$
|
562
|
|
|
Reid Gardner No. 4
|
|
|
32.2
|
|
|
|
127,970
|
|
|
|
79,425
|
|
|
|
48,545
|
|
|
|
7,538
|
|
|
Silverhawk
|
|
|
75.0
|
|
|
|
235,241
|
|
|
|
27,097
|
|
|
|
208,144
|
|
|
|
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total NPC
|
|
|
|
|
|
$
|
603,561
|
|
|
$
|
234,029
|
|
|
$
|
369,532
|
|
|
$
|
8,160
|
|
|
SPPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valmy Facility
|
|
|
50.0
|
|
|
$
|
293,236
|
|
|
$
|
171,660
|
|
|
$
|
121,576
|
|
|
$
|
9,132
|
|
The amounts for Navajo include NPC’s share of transmission systems, general plant
equipment and NPC’s share of the jointly owned railroad which delivers coal to the plant. Each
participant provides its own financing for all of these jointly owned
136
facilities. NPC’s share of
operating expenses for these facilities is included in the corresponding operating expenses in its
Consolidated Income Statements.
NPC is the operator of the Silverhawk generating station, which is jointly owned with Southern
Nevada Water Authority. NPC owns 75% and its share of direct operation and maintenance expense is
included in its accompanying Consolidated Income Statements.
NPC has an approximate 14% ownership in the Mohave Generating Station (“Mohave”). Southern
California Edison is the operating partner of Mohave. On December 31, 2005, Mohave ceased
operations due to unresolved legal matters, as such it was reclassified from Plant-in-Service to
Other Regulatory Assets as of December 31, 2005. See Note 13, Commitments and Contingencies, for
further discussion of Mohave.
SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy generating
station, with each company being responsible for financing its share of capital and operating
costs. SPPC is the operator of the plant for both parties. SPPC’s share of direct operation and
maintenance expenses for Valmy is included in its accompanying Consolidated Income Statements.
NOTE 6. LONG-TERM DEBT
As of December 31, 2006, NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for
long-term debt (including obligations related to capital leases) for the next five years and
thereafter are shown below (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR Holding Co. and
|
|
|
|
|
|
|
|
NPC
|
|
|
SPPC
|
|
|
Other Subs.
|
|
|
SPR Consolidated
|
|
|
2007
|
|
$
|
5,948
|
|
|
$
|
2,400
|
|
|
$
|
—
|
|
|
$
|
8,348
|
|
|
2008
|
|
|
7,068
|
|
|
|
322,400
|
|
|
|
—
|
|
|
|
329,468
|
|
|
2009
|
|
|
22,138
|
|
|
|
80,600
|
|
|
|
—
|
|
|
|
102,738
|
|
|
2010
|
|
|
7,843
|
|
|
|
—
|
|
|
|
—
|
|
|
|
7,843
|
|
|
2011
|
|
|
369,734
|
|
|
|
—
|
|
|
|
—
|
|
|
|
369,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
412,731
|
|
|
|
405,400
|
|
|
|
—
|
|
|
|
818,131
|
|
|
Thereafter
|
|
|
1,986,113
|
|
|
|
668,250
|
|
|
|
549,209
|
|
|
|
3,203,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,398,844
|
|
|
|
1,073,650
|
|
|
|
549,209
|
|
|
|
4,021,703
|
|
|
Unamortized Premium (Discount) Amount
|
|
|
(12,757
|
)
|
|
|
(392
|
)
|
|
|
1,336
|
|
|
|
(11,813
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,386,087
|
|
|
$
|
1,073,258
|
|
|
$
|
550,545
|
|
|
$
|
4,009,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The preceding table includes obligations related to capital lease obligations discussed
under lease commitments within this note.
Substantially all utility plant is subject to the liens of NPC’s and SPPC’s indentures under
which their respective General and Refunding Mortgage bonds are issued.
Nevada Power Company
Pollution Control Refunding Revenue Bonds, Series 2006, 2006A and 2006B
In August 2006, on behalf of NPC, Clark County, Nevada (Clark County) issued $39.5 million
aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006, due
January 2036. On the same date, on behalf of NPC, Coconino County, Arizona Pollution Control
Corporation (Coconino County) issued $40 million aggregate principal amount of its Pollution
Control Refunding Revenue Bonds, Series 2006A, due September 2032, and $13 million aggregate
principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006B, due March 2039.
In connection with the issuance of these Bonds, NPC entered into financing agreements with
Clark County and Coconino County, pursuant to which Clark County and Coconino County loaned the
proceeds from the sales of the bonds to NPC. NPC’s payment obligations under the financing
agreements are secured by NPC’s General and Refunding Mortgage Notes, Series P.
The interest rates of the Bonds were initially determined by an auction. The method of
determining the interest rate on the Bonds may be converted from time to time so that such Bonds
would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.
The proceeds of the offering were used to refund the following, all of which were previously
issued for the benefit of NPC:
|
|
•
|
|
$39.5 million principal amount of Clark County’s Pollution Control Refunding Revenue Bonds, Series 1992B,
|
|
|
|
|
•
|
|
$20 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1996,
|
|
|
|
|
•
|
|
$20 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1997B, and
|
|
|
|
|
•
|
|
$13 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1995E.
|
137
General and Refunding Mortgage Notes, Series O
In May 2006, NPC issued and sold $250 million in aggregate principal amount of 6.5% General
and Refunding Mortgage Notes, Series O, due 2018. The Series O Notes were issued with registration
rights. Proceeds of the offering, together with available cash, were utilized to:
|
|
•
|
|
fund the early redemption of $78 million aggregate principal amounts of NPC’s 7.2%
Industrial Development Revenue Bonds, Series 1992 C, due 2022,
|
|
|
|
|
•
|
|
fund the early redemption, in June 2006, of approximately $72.2 million aggregate
principal amount of NPC’s 7.75% Junior Subordinated Debentures due 2038 (when the
debentures were repaid upon redemption, the proceeds from the repayment were used to
simultaneously redeem an equal amount of the 7.75% Cumulative Quarterly Preferred
Securities of NVP Capital III, a wholly-owned subsidiary of NPC),
|
|
|
|
|
•
|
|
repay amounts outstanding under NPC’s revolving credit facility.
|
In June 2006, NPC issued an additional $75 million in aggregate principal amount of its 6.5%
General and Refunding Mortgage Notes, Series O, as part of the same series as the original Series O
Notes. The aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due
2018, outstanding is $325 million as of December 31, 2006. The proceeds from the second issuance,
along with the proceeds from an offering of $120 million of NPC’s 6.65% General and Refunding
Mortgage Notes, Series N, due 2036 (described below) were used to pay the total consideration for
the tender offer for the 10.875% General and Refunding Mortgage Notes, Series E, described below.
General and Refunding Mortgage Notes, Series N
In April 2006, NPC issued and sold $250 million of its 6.65% General and Refunding Mortgage
Notes, Series N, due April 2036. The Series N Notes were issued with registration rights. Proceeds
of the offering, together with available cash, were utilized to:
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fund the early redemption of $35 million aggregate principal amount of NPC’s 8.50%
Series Z First Mortgage Bonds due 2023 plus approximately $1 million of associated
redemption premiums,
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fund the early redemption of $105 million aggregate principal amount of 6.70%
Industrial Development Revenue Bonds, due 2022, and
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fund the early redemption of approximately $122.5 million aggregate principal amount
of NPC’s 8.20% Junior Subordinated Debentures due 2037 (when the debentures were repaid
upon redemption, the proceeds from the
repayment were used to simultaneously redeem an equal amount of the 8.20% Cumulative
Quarterly Preferred Securities of NVP Capital I, a wholly-owned subsidiary of NPC).
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In June 2006, NPC issued an additional $120 million in aggregate principal amount of its 6.65%
General and Refunding Mortgage Notes, Series N, as part of the same series as the original Series N
Notes. The aggregate principal amount of 6.65% General and Refunding Mortgage Notes, Series N, due
2036, outstanding is $370 million as of December 31, 2006. The proceeds from the second issuance,
along with the proceeds from an offering of $75 million of NPC’s 6.5% General and Refunding
Mortgage Notes, Series O, due 2018 (described above) were used to pay the total consideration for
the tender offer on the 10.875% General and Refunding Mortgage Notes, Series E, described below.
General and Refunding Mortgage Notes, Series M
In January 2006, NPC issued and sold $210 million of its 5.95% General and Refunding Mortgage
Notes, Series M, due March 2016. The Series M Notes were issued with registration rights. In
February 2006 the net proceeds of the issuance plus available cash were used to repay $210 million
of amounts outstanding under NPC’s revolving credit facility, which were borrowed to finance the
purchase of a 75% ownership interest in the Silverhawk Generating Facility.
Revolving Credit Facility
In November 2005, NPC amended and restated its existing secured $350 million revolving credit
facility, maturing in October 2007, reducing the fees on both the unused portion of the facility
and on the amounts borrowed, increasing the size of the facility to $500 million, extending the
maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank,
National Association. The rate for outstanding loans and/or letters of credit under the revolving
credit facility will be at either an applicable base rate (defined as the higher of the Prime rate
and the Federal Funds rate plus one-half of one percent) or a Eurodollar rate plus a margin that
varies based upon NPC’s credit rating by at least two of the three rating agencies: Standard &
Poor’s (“S&P”), Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings Ltd. (“Fitch”).
Currently, the base rate is Prime, and NPC’s applicable base rate margin is zero. The Eurodollar
margin is 0.875%.
138
In April 2006, NPC increased the size of the credit facility to $600 million. The facility
will provide additional liquidity for increased commodity prices and temporary bridge financing of
capital expenditures. As of December 31, 2006, NPC had $55 million of letters of credit
outstanding and had no borrowings outstanding under the revolving credit facility. As of February
23, 2007, NPC had $48.7 million of letters of credit outstanding and had $75 million borrowed under
the revolving credit facility.
The NPC Credit Agreement contains two financial maintenance covenants. The first requires that
NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the
last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that NPC maintain a
ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of
each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to
1. As of December 31, 2006, NPC was in compliance with these covenants.
The NPC Credit Agreement provides for an event of default if there is a failure under NPC’s
other financing agreements to meet certain payment terms or to observe other covenants that would
result in an acceleration of payments due.
The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends.
These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions.
Other Redemptions
General and Refunding Mortgage Notes, Series G
In July 2005, NPC redeemed $122,500,000 aggregate principal amount of its 9% General and
Refunding Mortgage Notes, Series G, due 2013. This redemption constituted 35% of the principal
amount outstanding. The Series G Notes were redeemed at a redemption price equal to $1,090.00 for
each $1,000 note redeemed for a redemption premium in excess of the principal amount of
approximately $11 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types
of Regulation, the redemption premium to redeem the debt will be amortized over the original term
of the debt.
General and Refunding Mortgage Notes, Series E
In July 2005, NPC redeemed $87,500,000 aggregate principal amount of its 10.875% General and
Refunding Mortgage Notes, Series E, due 2009. This redemption constituted 35% of the principal
amount outstanding. The Series E Notes were redeemed at a redemption price equal to $1,108.75 for
each $1,000 note redeemed for a redemption premium in excess of the principal amount of
approximately $9.5 million. In accordance with SFAS 71, Accounting for the Effects of Certain
Types of Regulation, the redemption premium to redeem the debt will be amortized over the original
term of the debt. NPC paid for the redemption with the proceeds of an equity contribution of
approximately $230.5 million from SPR.
Tender Offer for General and Refunding Mortgage Notes, Series E
In June 2006, NPC commenced a tender offer for the remaining 10.875% General and Refunding
Mortgage Notes, Series E, due 2009. In conjunction with that offer, NPC solicited the consent of
holders of a majority in aggregate principal amount of the Series E Notes to eliminate
substantially all of the restrictive covenants contained in the officer’s certificate governing the
Series E Notes. Approximately $150 million of $162.5 million Series E Notes outstanding were
validly tendered and accepted by NPC. Those holders who tendered the Series E Notes and delivered
their consents by June 14, 2006 were entitled to receive a consent payment of $30 per $1,000
principal amount of Series E Notes, plus tender consideration for each $1,000 principal amount of
Series E Notes validly tendered. Those holders who tendered the Series E Notes after June 14,
2006, but prior to June 28, 2006, were entitled to receive the tender consideration only. This
tender consideration was $1,038.45 in cash plus accrued and unpaid interest up to the June 2006
settlement date per $1,000 principal amount of the Series E Notes tendered. Proceeds from the June
2006 issuance of Series N and Series O Notes (discussed above) were used to fund the tender offer.
The total consideration (including the consent payment and accrued interest) paid in June 2006 was
approximately $163.6 million. In October 2006, NPC redeemed the remaining $12.6 million aggregate
principal amount of the Series E Notes, plus accrued interest, using available cash on hand.
NVP Capital I Trust
In April 2006, NPC’s 8.20% Junior Subordinated Debentures due 2037 were redeemed. When the
debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously
redeem an equal amount of the 8.20% Cumulative Quarterly Preferred Securities of NVP Capital I.
NVP Capital III Trust
In June 2006, NPC’s 7.75% Junior Subordinated Debentures due 2038 were redeemed. When the
debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously
redeem an equal amount of the 7.75% Cumulative Quarterly Preferred Securities of NVP Capital III.
139
Sierra Pacific Power Company
Pollution Control and Gas and Water Facilities Refunding Revenue Bonds, Series 2006, 2006A, 2006B
and 2006C
In November 2006, on behalf of SPPC, Humboldt County, Nevada (Humboldt County) issued $49.75
million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006,
due October 2029. On the same date, on behalf of SPPC, Washoe County, Nevada (Washoe County)
issued $58.7 million aggregate principal amount of it Gas Facilities Refunding Revenue Bonds,
Series 2006A, due August 2031; $75 million aggregate principal amount of its Water Facilities
Refunding Revenue Bonds, Series 2006B, due March 2036; and $84.8 million aggregate principal amount
of its Gas and Water Facilities Refunding Revenue Bonds, Series 2006C, due March 2036.
In connection with the issuance of these Bonds, SPPC entered into financing agreements with
Humboldt County and Washoe County, pursuant to which Humboldt County and Washoe County loaned the
proceeds from the sales of the bonds to SPPC. SPPC’s payment obligations under the financing
agreements are secured by SPPC’s General and Refunding Mortgage Notes, Series N.
The interest rates of the Bonds were initially determined by an auction. The method of
determining the interest rate on the Bonds may be converted from time to time so that such Bonds
would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.
The proceeds of the offerings were used to refund the following, all of which were previously
issued for the benefit of SPPC:
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$17.5 million principal amount of 6.65% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1987
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$20 million principal amount of 6.55% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1990
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$21.2 million principal amount of 6.70% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1992
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$75 million principal amount of 6.65% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1987
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$45 million principal amount of 6.30% Washoe County’s Gas and Water Facilities Refunding
Revenue Bonds, Series 1987
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$30 million principal amount of 5.90% Washoe County’s Gas and Water Facilities Refunding
Revenue Bonds, Series 1993B
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$9.8 million principal amount of 5.90% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1993A
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$39.5 million principal amount of 6.55% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1987
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$10.25 million principal amount of 6.30% Humboldt County’s Pollution Control Refunding
Revenue Bonds, Series 1992A
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Humboldt County Pollution Control Refunding Revenue Bonds
In October 2006, the 6.35% Humboldt County Pollution Control Refunding Revenue Bonds, Series
1992B, due August 2022, in the amount of $1 million were redeemed at 100% of the stated principal
amount, plus accrued interest.
General and Refunding Mortgage Notes, Series M
In March 2006, SPPC issued and sold $300 million of its 6.00% General and Refunding Mortgage
Notes, Series M, due May 2016. The Series M Notes were issued with registration rights. Proceeds
of the offering were used to repay $173 million borrowed under the revolving credit facility that
was utilized to:
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fund the early redemption of $110 million aggregate principal amount of SPPC’s
Collateralized Medium Term 6.95% to 8.61% Series A Notes due 2022;
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fund the early redemption of $58 million aggregate principal amount of SPPC’s
Collateralized Medium Term 7.10% to 7.14% Series B Notes due 2023;
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pay for maturing debt of $30 million aggregate principal amount of SPPC’s Collateralized
Medium Term 6.81% to 6.83% Series C Notes due 2006;
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pay for $51 million in connection with the redemption of $50 million of SPPC’s Series A
Preferred Stock (two million shares of stock were redeemed at a redemption price per share
of $25.683, plus accrued dividends to the redemption date of $.4875 per share); and
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pay for maturing debt of $20 million aggregate principal amount of SPPC’s Collateralized
Medium Term 6.62% to 6.65% Series C Notes due 2006.
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Revolving Credit Facility
In November 2005, SPPC amended and restated its existing secured $50 million revolving credit
facility, maturing in October 2007, reducing the fees on both the unused portion of the facility,
and on the amounts borrowed, increasing the size of the facility to $250 million, extending the
maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank,
National Association. The rate for outstanding loans and/or letters of credit under the revolving
credit facility will be at either an applicable base rate (defined as the higher of the Prime rate
and the Federal Funds rate plus one-half of one percent) or a Eurodollar
140
rate, plus a margin that
varies based upon SPPC’s credit rating by at least two of the three rating agencies (S&P, Moody’s
and Fitch). Currently, the base rate is Prime and SPPC’s applicable base rate margin is zero. The
current Eurodollar margin is 0.875%.
In April 2006, SPPC increased the size of its credit facility to $350 million. The facility
will provide additional liquidity for increased commodity prices and temporary bridge financing of
capital expenditures. As of December 31, 2006, SPPC had $9.4 million of letters of credit
outstanding and had no amounts borrowed under the revolving credit facility. As of February 23,
2007, SPPC had $18.9 million of letters of credit and had no amounts borrowed under the revolving
credit facility.
The SPPC Credit Agreement contains two financial maintenance covenants. The first requires
that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of
the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC
maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the
last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less
than 2.0 to 1. As of December 31, 2006, SPPC was in compliance with these covenants.
The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC’s
other financing agreements to meet certain payment terms or to observe other covenants that would
result in an acceleration of payments due.
The SPPC Credit Agreement, similar to SPPC’s Series H Notes, places certain restrictions on
debt incurrence, liens and dividends. These limitations are discussed in Note 8, Debt Covenant and
Other Restrictions.
Sierra Pacific Resources
Tender Offer
In November 2006, SPR commenced tender offers for up to $110 million aggregate principal
amount of its 7.803% Senior Notes due 2012, its 8.625% Senior Notes due 2014, and its 6.75% Senior
Notes due 2017. Each of the offers was conditioned on SPR purchasing no more than an aggregate
principal amount of $110 million of all notes validly tendered. To meet this condition, SPR
terminated the offer for the 6.75% Notes. In December 2006 approximately $25 million of the 7.803%
Senior Notes outstanding, and approximately $85 million of the 8.625% Senior Notes outstanding were
validly tendered and accepted by SPR. The total consideration paid was approximately $120.6
million (which included an early tender premium and accrued interest). As of December 31, 2006,
the outstanding balances for the 7.803% Senior Notes and 8.625%
Senior Notes were $ 74.2 million
and $250.0 million, respectively.
7.803% Senior Notes
In May 2005, SPR issued $99,142,000 aggregate principal amount of 7.93% Senior Notes, due
2007. These senior notes replaced the notes associated with the Premium Income Equity Securities
(Old PIES), which were originally issued in November 2001. SPR successfully remarketed these notes
in June 2005. In connection with the remarketing, the interest rate of the senior notes was reset
to 7.803% per annum, effective on and after June 14, 2005. The remarketed senior notes will mature
in June 2012. In December 2006, a portion of these Notes were tendered. (See Tender Offer above).
As of December 31, 2006, $74.2 million aggregate principal amount of the 7.803% Senior Notes remain
outstanding.
6.75% Senior Notes
In August 2005, SPR conducted a private placement of $225 million 6.75% Senior Notes due 2017.
The proceeds were used to repurchase approximately $141 million 7.93% Senior Notes associated with
the Old PIES, pay approximately $54 million in premiums associated with the conversion of the 7.25%
Notes and fund the associated fees and expenses; and to provide additional liquidity to SPR.
8.625% Senior Notes
In March 2004, SPR issued and sold $335 million 8.625% Senior Unsecured Notes due March 2014.
The Senior Unsecured Notes, which were issued with registration rights, were exchanged for
registered notes in October 2004. The proceeds of the issuance were used to fund the repurchase of
approximately $174 million in principal amount of SPR’s 8.75% Notes due 2005 at a price equal to
approximately 107.225% of the principal amount thereof that were tendered pursuant to SPR’s tender
offer.
The balance of the net proceeds were used in May 2004 to legally extinguish the approximately
$126 million of remaining principal amount of SPR’s 8.75% Notes due 2005 which were not tendered,
and to pay associated interest and fees and expenses associated with the tender offer and the Notes
offering. The total cost to extinguish the debt was approximately $23.7 million consisting of
tender fees, interest costs and unamortized debt issuance costs.
In December 2006, a portion of the 8.625% Senior Unsecured Notes were tendered (See Tender
Offer above). As of December 31, 2006, $250 million aggregate principal amount of the 8.625%
Senior Notes remain outstanding.
141
Lease Commitments
In 1984, NPC entered into a 30-year capital lease with five-year renewal options beginning in
year 2015. The fixed rental obligation for the first 30 years is $5.1 million per year. Also, NPC
has a power purchase contract with Nevada Sun-Peak Limited Partnership. The contract contains a
buyout provision for the facility at the end of the contract term in 2016. The facility is situated
on NPC property.
Future cash payments for these capital leases, combined, as of December 31, 2006, were as
follows (dollars in thousands):
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2007
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$
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5,933
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2008
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7,053
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2009
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7,138
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2010
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7,843
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2011
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5,734
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Thereafter
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16,778
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NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The December 31, 2006, carrying amount of cash and cash equivalents, current assets, accounts
receivable, accounts payable and current liabilities approximates fair value due to the short-term
nature of these instruments.
The total fair value of NPC’s consolidated long-term debt at December 31, 2006, is estimated
to be $2.5 billion (excluding current portion) based on quoted market prices for the same or
similar issues or on the current rates offered to NPC for debt of the same remaining maturities.
The total fair value (excluding current portion) was estimated to be $2.2 billion at December 31,
2005.
The total fair value of SPPC’s consolidated long-term debt at December 31, 2006, is estimated
to be $1.1 billion (excluding current portion) based on quoted market prices for the same or
similar issues or on the current rates offered to SPPC for debt of the same remaining maturities.
The total fair value (excluding current portion) was estimated to be $1.0 billion as of December
31, 2005.
The total fair value of SPR’s consolidated long-term debt at December 31, 2006 is estimated to
be $4.1 billion (excluding current portion) based on quoted market prices for the same or similar
issues or on the current rates offered to SPR for debt of the same remaining maturities. The total
fair value (excluding current portion) was estimated to be $3.9 billion as of December 31, 2005.
NOTE 8. DEBT COVENANT AND OTHER RESTRICTIONS
Dividends
from subsidiaries
Since SPR is a holding company,
substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on
their common stock, all of which is owned by SPR. 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 the PUCN order for Docket 05-10024 and 05-10025, issued in February 2006, a
dividend restriction was instituted for both Utilities. Under this restriction,
the combined amount that NPC and SPPC may pay to SPR each year is limited to the actual
cash necessary to service SPR’s debt for the year. At the time of the order, SPR and the
Utilities were only rated by Standard & Poor’s (“S&P”), Moody’s Investors Service, Inc.
(“Moody’s”) and Fitch Ratings Ltd. (“Fitch”). The PUCN order states that the dividend
restriction will continue until NPC’s and SPPC’s senior secured debt obtains an investment
grade rating from two of the three credit rating agencies, but did not specify which rating
agencies. In February 2007, Dominion Bond Rating Service (“DBRS”), who had not previously
issued ratings on the companies, assigned ratings for SPR, NPC and SPPC. DBRS and Fitch
currently rate NPC and SPPC’s senior secured debt at the minimum level for investment grade.
It is not clear what effect, if any, the DBRS rating will have on the
PUCN dividend restriction. See “Credit Ratings” below for discussion of current ratings.
In addition, certain agreements entered into by the Utilities set restrictions on certain
restricted payments, including the amount of dividends they may declare and pay and restrict the
circumstances under which such dividends may be declared and paid.
In addition, covenants of certain SPR, NPC and SPPC debt limit the company’s ability to incur
additional debt. Material restrictions on dividends and on debt incurrence, contained in SPR’s and
the Utilities’ financing agreements are summarized below. All securities issued by NPC and SPPC
must be authorized by the PUCN.
Limits on Restricted Payments
Sierra Pacific Resources
SPR has paid no dividends since 2002. Dividends are considered periodically by SPR’s Board of
Directors and are subject to factors that ordinarily affect dividend policy, such as current and
prospective earnings, current and prospective business conditions, regulatory factors, SPR’s
financial conditions and other matters within the discretion of the Board, as well as dividend
restrictions set forth in SPR’s 8 5/8% Senior Notes due 2014, 7.803% Senior Notes due 2012 and
6.75% Senior Notes due 2017. The Board will continue to review the factors described above on a
periodic basis to determine if and when it would be prudent to declare a dividend on SPR’s Common
Stock. There is no guarantee that dividends will be paid in the future, or that, if paid, the
dividends will be paid at the same amount or with the same frequency as in the past.
142
Certain of SPR debt contain covenants that limit restricted payments, which include dividends.
If SPR were to resume paying a dividend, these restrictive covenants must first be satisfied. SPR
must be able to incur additional indebtedness, as determined under a 2 to 1 fixed charge coverage
ratio test. If that condition is met, the amount of dividends that can be paid is less than (i) 50%
of the Consolidated Net Income for SPR for the period from April 1, 2004 to the end of the most
recently ended fiscal quarter for which internal financial statements are available at the time of
such payment, plus (ii) 100% of SPR’s net cash proceeds from the issuance or
sale of its equity interests, including common stock. Since SPR meets the 2 to 1 fixed charge
coverage ratio test, it could dividend up to a maximum of $740 million as of December 31, 2006.
Under its most restrictive covenants, SPR can additionally pay up to an aggregate of $50 million in
dividends during the period from April 1, 2004 to the end of the most recently ended fiscal
quarter.
Material Dividend Restrictions Applicable to Nevada Power Company
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The following notes and credit agreement limit the amount of payments in respect of
common stock that NPC may make to SPR:
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NPC’s
5
7
/
8
General and Refunding Mortgage Notes, Series L, due 2015, which were issued in November 2004,
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o
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NPC’s Revolving Credit Agreement, which was amended and
restated in November 2005,
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o
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NPC’s 6
1
/
2
% General and Refunding Mortgage Notes, Series I, due 2012, which were issued in April 2004, and
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o
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NPC’s 9% General and Refunding Mortgage Notes, Series G, due 2013, which were issued in August 2003.
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However, the dividend payment limitation does not apply to payments by NPC to enable SPR to
pay its reasonable fees and expenses, provided that:
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those payments do not exceed $60 million for any one calendar year,
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o
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those payments comply with any regulatory restrictions then applicable to NPC, and
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o
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the ratio of consolidated cash flow to fixed charges for NPC’s most
recently ended four full fiscal quarters immediately preceding the date of payment
is at least 1.75 to 1.
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The terms of the various series of Notes, and the Revolving Credit Agreement also permit
NPC to make payments to SPR in excess of the amounts payable discussed above in an
aggregate amount not to exceed:
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under the Series G, Series I and Series L Notes, $25 million from the
date of the issuance of the Series G, Series I and Series L Notes, respectively.
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o
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Under the Second Amended and Restated Revolving Credit Facility, $50
million from the date of the establishment of the Amended and Restated Revolving
Credit Facility.
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In addition, NPC may make payments to SPR in excess of the amounts described above so long
as, at the time of payment and after giving effect to the payment:
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i.
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there are no defaults or events of default with respect to the
Series G, I and L Notes or the Revolving NPC Credit Agreement,
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ii.
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NPC has a ratio of consolidated cash flow to fixed charges for
NPC’s most recently ended four full fiscal quarters immediately preceding the
payment date of at least 2 to 1, and
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iii.
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the total amount of such dividends is less than:
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the sum of 50% of NPC’s consolidated net income measured on a annual basis
cumulative of all quarters from the date of issuance of the applicable series
of Notes, the Bond or Credit Agreement, plus
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100% of NPC’s aggregate net cash proceeds from contributions to its common
equity capital or the issuance or sale of certain equity or convertible debt
securities of NPC, plus
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the lesser of cash return of capital or the initial amount of certain restricted investments, plus
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the fair market value of NPC’s investment in certain subsidiaries.
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Since NPC meets (i) and (ii) above, NPC would be able to pay up to a maximum of
$609 million to SPR as of December 31, 2006. However, the
total amount of dividends that NPC can pay to SPR under its financing
agreements does not currently significantly restrict their ability
to pay dividends because the maximum amount of dividends that can be
paid under its financing agreements is greater than the amount that
NPC can pay under the PUCN dividend restriction.
If NPC’s Series, Series G Notes, Series I Notes, or Series L Notes are upgraded to investment
grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect
so long as the applicable series of Notes remains investment grade (see Credit Ratings below).
143
Material Dividend Restrictions Applicable to Sierra Pacific Power Company
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The following notes and credit facility limit the amount of payments in respect of
common stock that SPPC may make to SPR:
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SPPC’s Revolving Credit Agreement, which was amended and restated in November 2005, and
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o
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SPPC’s 6
1
/
4
% General and Refunding Mortgage Notes, Series H, due 2012, which were issued in April 2004.
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However, the dividend payment limitation does not apply to payments by SPPC to enable SPR
to pay its reasonable fees and expenses provided that:
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those payments do not exceed $50 million for any one calendar year,
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those payments comply with any regulatory restrictions then applicable to SPPC, and
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the ratio of consolidated cash flow to fixed charges for SPPC’s most
recently ended four full fiscal quarters immediately preceding the date of payment
is at least 1.75 to 1.
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The terms of the Series H Notes also permit SPPC to make payments to SPR in excess of the
amounts payable discussed above in an aggregate amount not to exceed $25 million from the
date of the issuance of the Series H Notes.
The terms of the Amended and Restated Revolving Credit Facility also permit SPPC to make
payments to SPR in excess of the amounts payable above in an aggregate amount not to exceed
$50 million from the date of the establishment of the Amended and Restated Revolving Credit
Facility.
In addition, SPPC may make payments to SPR in excess of the amounts described above so long
as, at the time of payment and after giving effect to the payment:
|
|
i.
|
|
there are no defaults or events of default with respect to the
Series H Notes or the SPPC Revolving Credit Agreement,
|
|
|
|
|
ii.
|
|
SPPC has a ratio of consolidated cash flow to fixed charges for
SPPC’s most recently ended four full fiscal quarters immediately preceding the
payment date of at least 2 to 1, and
|
|
|
|
|
iii.
|
|
the total amount of such dividends is less than:
|
|
|
•
|
|
the sum of 50% of SPPC’s consolidated net income measured on a annual basis
cumulative of all quarters from the date of issuance of the Series H Notes or
the establishment of the Revolving Credit Agreement, plus
|
|
|
|
|
•
|
|
100% of SPPC’s aggregate net cash proceeds from contributions to its common
equity capital or the issuance or sale of certain equity or convertible debt
securities of SPPC, plus
|
|
|
|
|
•
|
|
the lesser of cash return of capital or the initial amount of certain restricted investments, plus
|
|
|
|
|
•
|
|
the fair market value of SPPC’s investment in certain subsidiaries.
|
Since SPPC meets (i) and (ii) above, SPPC would be able to pay up to a maximum of
$126 million to SPR as of December 31, 2006. However, the
total amount of dividends that SPPC can pay to SPR under its financing
agreements does not currently significantly restrict their ability
to pay dividends because the maximum amount of dividends that can be
paid under its financing agreements is greater than the amount that
SPPC can pay under the PUCN dividend restriction.
If SPPC’s Series H Notes are upgraded to investment grade by both Moody’s and S&P, these
restrictions will be suspended and will no longer be in effect so long as the applicable series of
Notes remain investment grade (see Credit Ratings below).
Dividend Restrictions Applicable to the Utilities
The Utilities are subject to the provision of the Federal Power Act that states that dividends
cannot be paid out of funds that are properly included in their capital account. 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 SPR could be jeopardized.
Limitations on Indebtedness
Sierra Pacific Resources
Certain debt of SPR places restrictions on debt incurrence, liens and dividends, unless, at
the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most
recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant
restriction, as of December 31, 2006, SPR would be allowed to incur up to $2.1 billion of
additional indebtedness on a consolidated basis.
144
Notwithstanding this restriction, under the terms of the debt, SPR would still be
permitted to incur debt including, but not limited to, obligations incurred to finance property
construction or improvement, certain intercompany indebtedness, or indebtedness incurred to finance
capital expenditures, pursuant to the two utilities’ integrated resource plans. NPC and SPPC would
also be permitted to incur a combined total of up to $500 million in indebtedness and letters of
credit under their respective revolving credit facilities.
If the debt is upgraded to investment grade by both Moody’s and S&P, these restrictions will
be suspended and will no longer be in effect so long as the applicable series of Notes remains
investment grade (see Credit Ratings below).
Nevada Power Company
Certain debt of NPC places restrictions on debt incurrence, liens and dividends, unless, at
the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC’s most
recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant
restriction, as of December 31, 2006, NPC would be allowed to incur $2.2 billion of additional
indebtedness. However, due to the terms of the SPR debt described above, NPC’s and SPPC’s combined
debt limit is restricted to the $2.1 billion of additional indebtedness SPR could incur on a
consolidated basis.
Under the terms of NPC’s debt, NPC would also be permitted to incur debt, including, but not
limited to, obligations incurred to finance property construction or improvements, certain
intercompany indebtedness, certain letters of credit indebtedness, or indebtedness incurred to
finance capital expenditures, pursuant to NPC’s 2006 Integrated Resource Plan.
If the debt containing these covenants is upgraded to investment grade by both Moody’s and
S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable
debt remains investment grade (see Credit Ratings below).
Sierra Pacific Power Company
Certain debt of SPPC places restrictions on debt incurrence, liens and dividends, unless, at
the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’s most
recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant
restriction, as of December 31, 2006, SPPC would be allowed to incur up to $797 million of
additional indebtedness on a consolidated basis. However, due to the terms of the SPR debt
described above, NPC’s and SPPC’s combined debt limit is restricted to the $2.1 billion of
additional indebtedness SPR could incur on a consolidated basis.
Under the terms of SPPC’s debt, SPPC would also be permitted to incur debt including, but not
limited to, obligations incurred to finance property construction or improvements, certain
intercompany indebtedness, certain letters of credit indebtedness, or indebtedness incurred to
finance capital expenditures, pursuant to SPPC’s 2004 Integrated Resource Plan.
If the debt containing these covenants is upgraded to investment grade by both Moody’s and
S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable
debt remains investment grade (see Credit Ratings below).
Credit Ratings
SPR, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations
S&P, Moody’s, Fitch, and Dominion Bond Rating Service (“DBRS”). As of February 23, 2007, the
ratings are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rating Agency
|
|
|
|
|
|
DBRS
|
|
Fitch
|
|
Moody’s
|
|
S&P
|
|
SPR
|
|
Sr. Unsecured Debt
|
|
BB (low)
|
|
BB-
|
|
B1
|
|
B
|
|
NPC
|
|
Sr. Secured Debt
|
|
BBB (low)*
|
|
BBB-*
|
|
Bal
|
|
BB+
|
|
NPC
|
|
Sr. Unsecured Debt
|
|
Not rated
|
|
BB
|
|
Not rated
|
|
B
|
|
SPPC
|
|
Sr. Secured Debt
|
|
BBB (low)*
|
|
BBB-*
|
|
Bal
|
|
BB+
|
|
|
|
|
|
*
|
|
Ratings are investment grade
|
In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new
ratings to SPR, NPC and SPPC. The ratings for the senior secured debt of NPC and SPPC are BBB
(low), which is the minimum level for investment grade. The rating assigned to SPR’s senior notes
is BB (low), which is non-investment grade. DBRS’s trend for all three companies is Stable.
In 2006, there were other changes to the ratings of the three companies. Fitch upgraded the
ratings of SPR and the Utilities. The ratings for the senior secured debt of NPC and SPPC were
increased to BBB-, the minimum level for investment grade. The senior unsecured debt for NPC was
upgraded from BB- to BB, which is still non-investment grade. Fitch revised the rating outlook
for SPR and the Utilities from Positive to Stable. S&P upgraded the ratings of NPC’s and SPPC’s
senior secured debt from BB to
145
BB+, one level below investment grade. Moody’s re-affirmed its ratings for NPC’s and SPPC’s
senior secured debt at Ba1, one level below investment grade.
At the time of the PUCN order for Dockets 05-10024 and 05-10025, (see Dividends from
Subsidiaries, above) SPR and the Utilities were only rated by S&P, Moody’s and Fitch. The PUCN
order states that the dividend restriction will continue until NPC’s and SPPC’s senior secured debt
obtains an investment grade rating from two of the three credit rating agencies, but did not
specify which rating agencies. It is not clear what effect the DBRS rating will have on the PUCN
dividend restriction.
NOTE 9. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)
SPR, SPPC, and NPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” as amended by SFAS No. 138, SFAS No. 149 and SFAS No. 155. As amended, SFAS No. 133
establishes accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities. It requires that
an entity recognize all derivatives as either assets or liabilities in the statement of financial
position, measure those instruments at fair value, and recognize changes in the fair value of the
derivative instruments in earnings in the period of change, unless the derivative meets certain
defined conditions and qualifies as an effective hedge. SFAS No. 133 also provides a scope
exception for contracts that meet the normal purchase and sales criteria specified in the standard.
The normal purchases and normal sales exception requires, among other things, physical delivery in
quantities expected to be used or sold over a reasonable period in the normal course of business.
Contracts that are designated as normal purchase and normal sales are accounted for under deferred
energy accounting and not recorded on the Consolidated Balance Sheets at fair value. A majority of
the contracts entered into by the Utilities meet the criteria specified for this exception.
The energy supply function encompasses the reliable and efficient operation of the Utilities
generation, the procurement of all fuels and power and resource optimization (i.e., physical and
economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity
prices. SPR’s and the Utilities’ objective in using derivative instruments is to reduce exposure
to energy price risk. Energy price risks result from activities that include the generation,
procurement and marketing of power and the procurement and marketing of natural gas. Derivative
instruments used to manage energy price risk from time to time may include: forward contracts,
which involve physical delivery of an energy commodity; over-the-counter options with financial
institutions and other energy companies, which mitigate price risk by providing the right, but not
the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which
require the Utilities to receive or make payments based on the difference between a specified price
and the actual price of the underlying commodity. These contracts allow the Utilities to reduce the
risks associated with volatile electricity and natural gas markets.
The following table shows the fair value of the open derivative positions recorded on the
Consolidated Balance Sheets of SPR, NPC, and SPPC, and the related regulatory assets/liabilities
that did not meet the normal purchase and normal sales exception criteria in SFAS No. 133. The fair
values of the open derivative positions are determined using quoted exchange prices, external
dealer prices, and available market pricing curves. Due to deferred energy accounting treatment
under which the Utilities operate, regulatory assets and liabilities are established to the extent
that electricity and natural gas derivative gains and losses are recoverable or payable through
future rates, once realized. This accounting treatment is intended to defer the recognition of
mark-to-market gains and losses on energy commodity transactions until the period of settlement and
to not recognize gains and losses on the Consolidated Statements of Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
December 31, 2005
|
|
|
|
Fair Value
|
|
Fair Value
|
|
|
|
(dollars in millions)
|
|
(dollars in millions)
|
|
|
|
SPR
|
|
NPC
|
|
SPPC
|
|
SPR
|
|
NPC
|
|
SPPC
|
|
Risk management assets- current
|
|
$
|
27.3
|
|
|
$
|
16.4
|
|
|
$
|
10.9
|
|
|
$
|
50.2
|
|
|
$
|
22.4
|
|
|
$
|
27.8
|
|
|
Risk management assets- noncurrent
|
|
$
|
7.6
|
|
|
$
|
5.4
|
|
|
$
|
2.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total risk management assets
|
|
$
|
34.9
|
|
|
$
|
21.8
|
|
|
$
|
13.1
|
|
|
$
|
50.2
|
|
|
$
|
22.4
|
|
|
$
|
27.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management liabilities- current
|
|
$
|
123.1
|
|
|
$
|
84.7
|
|
|
$
|
38.4
|
|
|
$
|
16.6
|
|
|
$
|
10.1
|
|
|
$
|
6.5
|
|
|
Risk management liabilities- noncurrent
|
|
$
|
10.8
|
|
|
$
|
7.1
|
|
|
$
|
3.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total risk management liabilities
|
|
$
|
133.9
|
|
|
$
|
91.8
|
|
|
$
|
42.1
|
|
|
$
|
16.6
|
|
|
$
|
10.1
|
|
|
$
|
6.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management regulatory net assets (liabilities)
|
|
$
|
122.9
|
|
|
$
|
83.9
|
|
|
$
|
39.0
|
|
|
$
|
(15.6
|
)
|
|
$
|
(.6
|
)
|
|
$
|
(15.0
|
)
|
As a result of the nature of operations and the use of mark-to-market accounting for
certain derivatives that do not meet the normal purchase and normal sales exception criteria,
mark-to-market fair values will fluctuate. The Utilities can not predict these fluctuations, but
the primary factors that cause changes in the fair values are the number and size of the Utilities
open derivative positions with its counterparties and the changes in forward commodity prices. The
decrease in net risk management assets as of December 31, 2006 as compared to December 31, 2005, is
due to unfavorable open derivative positions on natural gas options held by
146
the Utilities to hedge
energy price risk for their customers, resulting from lower commodity prices for natural gas in
2006 relative to contract prices.
Also included in total risk management assets were $24.0 million, $13.9 million, and $10.1
million in payments for electric and gas options by SPR, NPC, and SPPC, respectively, at December
31, 2006.
NOTE 10. INCOME TAXES (BENEFITS)
Sierra Pacific Resources
The following reflects the composition of taxes on income from continuing operations (dollars
in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Provision (benefit) for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
5,914
|
|
|
$
|
3,159
|
|
|
$
|
(161
|
)
|
|
State
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
5,914
|
|
|
|
3,159
|
|
|
|
(161
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
144,919
|
|
|
|
43,833
|
|
|
|
24,448
|
|
|
State
|
|
|
494
|
|
|
|
1,688
|
|
|
|
(775
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
145,413
|
|
|
|
45,521
|
|
|
|
23,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of excess deferred taxes
|
|
|
(2,315
|
)
|
|
|
(2,123
|
)
|
|
|
(2,196
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of investment tax credits
|
|
|
(3,407
|
)
|
|
|
(3,439
|
)
|
|
|
(3,266
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
145,605
|
|
|
$
|
43,118
|
|
|
$
|
18,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income statement classification of provision (benefit) for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
91,571
|
|
|
$
|
39,185
|
|
|
$
|
22,739
|
|
|
Other income
|
|
|
54,034
|
|
|
|
3,933
|
|
|
|
(4,689
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
145,605
|
|
|
$
|
43,118
|
|
|
$
|
18,050
|
|
|
|
|
|
|
|
|
|
|
|
|
147
The total income tax provision differs from amounts computed by applying the federal
statutory tax rate to income before income taxes for the following reasons (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Income from continuing operations
|
|
$
|
279,792
|
|
|
$
|
86,137
|
|
|
$
|
30,842
|
|
|
Total income tax expense (benefit)
|
|
|
145,605
|
|
|
|
43,118
|
|
|
|
18,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pretax income
|
|
|
425,397
|
|
|
|
129,255
|
|
|
|
48,892
|
|
|
Statutory tax rate
|
|
|
35
|
%
|
|
|
35
|
%
|
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal income tax expense at statutory rate
|
|
|
148,889
|
|
|
|
45,239
|
|
|
|
17,112
|
|
|
Depreciation related to difference in costs basis for tax purposes
|
|
|
4,709
|
|
|
|
4,559
|
|
|
|
4,834
|
|
|
Allowance for funds used during construction — equity
|
|
|
(6,379
|
)
|
|
|
(7,113
|
)
|
|
|
(2,082
|
)
|
|
ITC amortization
|
|
|
(3,407
|
)
|
|
|
(3,439
|
)
|
|
|
(3,266
|
)
|
|
Goodwill
|
|
|
2,600
|
|
|
|
2,230
|
|
|
|
6,332
|
|
|
Convertible bond mark to market and interest accretion
|
|
|
—
|
|
|
|
2,132
|
|
|
|
2,786
|
|
|
Pension benefit plan
|
|
|
338
|
|
|
|
(945
|
)
|
|
|
(3,684
|
)
|
|
Research and development credit
|
|
|
(3,764
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Other — net
|
|
|
2,619
|
|
|
|
455
|
|
|
|
(632
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes before effect of income tax settlements
|
|
$
|
145,605
|
|
|
$
|
43,118
|
|
|
$
|
21,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate before effect of income tax settlements
|
|
|
34.2
|
%
|
|
|
33.3
|
%
|
|
|
43.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Effects of income tax settlements
|
|
|
|
|
|
|
—
|
|
|
|
(3,350
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
$
|
145,605
|
|
|
$
|
43,118
|
|
|
$
|
18,050
|
|
|
Effective tax rate
|
|
|
34.2
|
%
|
|
|
33.3
|
%
|
|
|
36.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by
the Internal Revenue Service (IRS) on a regular basis. The IRS is currently conducting audits of
SPR for the years 1997-2004. During the first quarter of 2004, SPR reached tentative agreements
with the IRS for certain matters. As a result of the tentative agreements, SPR recognized tax
benefits which increased net income by approximately $3.4 million in 2004. SPR believes that it
has adequately provided reasonable reserves for reasonable and foreseeable outcomes related to
uncertain tax matters.
148
The net deferred income tax liability consists of deferred income tax liabilities less related
deferred income tax assets, as shown (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Deferred income tax assets
|
|
|
|
|
|
|
|
|
|
Net operating loss and credit carryovers
|
|
$
|
227,834
|
|
|
$
|
247,135
|
|
|
Employee benefit plans
|
|
|
71,820
|
|
|
|
10,190
|
|
|
Customer advances
|
|
|
32,163
|
|
|
|
59,522
|
|
|
Gross-ups received on contribution in aid of construction and customer advances
|
|
|
31,113
|
|
|
|
25,862
|
|
|
Deferred revenues
|
|
|
1,586
|
|
|
|
11,303
|
|
|
Provision for contract termination
|
|
|
508
|
|
|
|
63,427
|
|
|
Other
|
|
|
22,128
|
|
|
|
19,765
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
387,152
|
|
|
|
437,204
|
|
|
Deferred income tax assets associated with regulatory matters
|
|
|
|
|
|
|
|
|
|
Excess deferred income taxes
|
|
|
15,111
|
|
|
|
17,426
|
|
|
Unamortized investment tax credit
|
|
|
18,964
|
|
|
|
20,798
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
34,075
|
|
|
|
38,224
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets before valuation allowance
|
|
|
421,227
|
|
|
|
475,428
|
|
|
Valuation allowance
|
|
|
(732
|
)
|
|
|
(984
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets after valuation allowance
|
|
$
|
420,495
|
|
|
$
|
474,444
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
|
Excess of tax depreciation over book depreciation
|
|
$
|
540,338
|
|
|
$
|
560,702
|
|
|
Deferred energy
|
|
|
192,653
|
|
|
|
180,488
|
|
|
Regulatory assets
|
|
|
101,375
|
|
|
|
20,139
|
|
|
Other
|
|
|
64,791
|
|
|
|
44,819
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
899,157
|
|
|
|
806,148
|
|
|
Deferred income tax liabilities associated with regulatory matters
|
|
|
|
|
|
|
|
|
|
Tax benefits flowed through to customers
|
|
|
263,170
|
|
|
|
249,262
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax liability
|
|
$
|
1,162,327
|
|
|
$
|
1,055,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liability
|
|
$
|
512,737
|
|
|
$
|
369,928
|
|
|
Net deferred income tax liability associated with regulatory matters
|
|
|
229,095
|
|
|
|
211,038
|
|
|
|
|
|
|
|
|
|
|
Total net deferred income tax liability
|
|
$
|
741,832
|
|
|
$
|
580,966
|
|
|
|
|
|
|
|
|
|
The
total 2006 net deferred income tax liability of $741,832 includes
$5,950 of deferred tax liability associated with accumulated
depreciation on the Mohave generating station, which, on the financial
statements, is included in other regulatory assets. Reference Note
13, Commitments and Contingencies, for further discussion of the
Mohave Generating Station.
SPR’s balance sheets contain a net regulatory asset of $229.1 million at December 31,
2006 and $211.0 million at December 31, 2005. The regulatory asset consists of future revenue to
be received from customers due to flow-through of the tax benefits of temporary differences and
goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future
revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist
of temporary differences for liberalized depreciation at rates in excess of current rates and
unamortized investment tax credits. The regulatory liability for temporary differences related to
liberalized depreciation will continue to be amortized using the average rate assumption method
required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused
by the investment tax credit will be amortized ratably in the same fashion as the accumulated
deferred investment credit.
As reflected in SPR’s balance sheet (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Tax benefits flowed through to customers
|
|
|
|
|
|
|
|
|
|
Related to property
|
|
$
|
106,175
|
|
|
$
|
98,330
|
|
|
Related to goodwill
|
|
|
156,995
|
|
|
|
150,931
|
|
|
|
|
|
|
|
|
|
|
Regulatory tax asset
|
|
|
263,170
|
|
|
|
249,261
|
|
|
|
|
Liberalized depreciation at rates in excess of current rates
|
|
|
15,111
|
|
|
|
17,426
|
|
|
Unamortized investment tax credits
|
|
|
18,964
|
|
|
|
20,798
|
|
|
|
|
|
|
|
|
|
|
Regulatory tax liability
|
|
|
34,075
|
|
|
|
38,224
|
|
|
|
|
|
|
|
|
|
|
Net regulatory tax asset
|
|
$
|
229,095
|
|
|
$
|
211,037
|
|
|
|
|
|
|
|
|
|
149
SPR and its subsidiaries file a consolidated federal income tax return. Current income
taxes are allocated based on SPR’s and each subsidiaries’ respective taxable income or loss and
investment tax credits as if each subsidiary filed a separate return.
SPR owes NPC $20.6 million
in inter-company tax payments. Additionally, per SPR’s tax sharing agreement, SPR has a current
tax receivable from SPPC of $9.1 million.
The following table summarizes the tax NOL and credit carry-forwards and associated
carry-forward periods, and a valuation allowance for amounts which SPR has determined that
realization is uncertain (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
|
|
|
|
|
Deferred Tax Asset
|
|
|
Valuation Allowance
|
|
|
Net Deferred Tax Asset
|
|
|
Period
|
|
|
Federal NOL
|
|
$
|
213,024
|
|
|
$
|
—
|
|
|
$
|
213,024
|
|
|
|
2020-2023
|
|
|
State NOLs
|
|
|
1,058
|
|
|
|
—
|
|
|
|
1,058
|
|
|
|
2008-2013
|
|
|
Research and
development credit
|
|
|
3,764
|
|
|
|
—
|
|
|
|
3,764
|
|
|
2021-2025
|
|
Alternative minimum tax credit
|
|
|
8,696
|
|
|
|
—
|
|
|
|
8,696
|
|
|
indefinite
|
|
Arizona coal credits
|
|
|
1,292
|
|
|
|
732
|
|
|
|
560
|
|
|
|
2007-2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
227,834
|
|
|
$
|
732
|
|
|
$
|
227,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2006, SPR has gross federal and state net operating loss carry-forwards
of $608.6 million and $12.0 million, respectively.
Considering all positive and negative evidence regarding the utilization of SPR’s deferred tax
assets, it has been determined that SPR is more-likely-than-not to realize all recorded deferred
tax assets, except the Arizona coal credits. As such, these Arizona coal credits represent the
only valuation allowance that has been recorded as of December 31, 2006.
Nevada Power Company
The following reflects the composition of taxes on income (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Provision (benefit) for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
4,865
|
|
|
$
|
3,159
|
|
|
$
|
6
|
|
|
State
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
4,865
|
|
|
|
3,159
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
114,741
|
|
|
|
63,873
|
|
|
|
58,762
|
|
|
State
|
|
|
268
|
|
|
|
(449
|
)
|
|
|
(67
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred, net
|
|
|
115,009
|
|
|
|
63,424
|
|
|
|
58,695
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of excess deferred taxes
|
|
|
(745
|
)
|
|
|
(778
|
)
|
|
|
(499
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of investment tax credits
|
|
|
(1,619
|
)
|
|
|
(1,810
|
)
|
|
|
(1,630
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
117,510
|
|
|
$
|
63,995
|
|
|
$
|
56,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income statement classification of provision for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
91,781
|
|
|
$
|
46,425
|
|
|
$
|
45,135
|
|
|
Other income
|
|
|
25,729
|
|
|
|
17,570
|
|
|
|
11,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
117,510
|
|
|
$
|
63,995
|
|
|
$
|
56,572
|
|
|
|
|
|
|
|
|
|
|
|
|
150
The total income tax provision differs from amounts computed by applying the federal
statutory tax rate to income before income taxes for the following reasons (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Income from continuing operations
|
|
$
|
224,540
|
|
|
$
|
132,734
|
|
|
$
|
104,312
|
|
|
Total income tax expense
|
|
|
117,510
|
|
|
|
63,995
|
|
|
|
56,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pretax income
|
|
|
342,050
|
|
|
|
196,729
|
|
|
|
160,884
|
|
|
Statutory tax rate
|
|
|
35
|
%
|
|
|
35
|
%
|
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal income tax expense at statutory rate
|
|
|
119,718
|
|
|
|
68,855
|
|
|
|
56,309
|
|
|
Depreciation related to difference in cost basis for tax purposes
|
|
|
2,192
|
|
|
|
1,880
|
|
|
|
2,144
|
|
|
Allowance for funds used during construction — equity
|
|
|
(4,114
|
)
|
|
|
(6,539
|
)
|
|
|
(1,481
|
)
|
|
ITC amortization
|
|
|
(1,619
|
)
|
|
|
(1,810
|
)
|
|
|
(1,630
|
)
|
|
Goodwill
|
|
|
1,646
|
|
|
|
1,386
|
|
|
|
1,732
|
|
|
Research and development credit
|
|
|
(1,666
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Other — net
|
|
|
1,353
|
|
|
|
223
|
|
|
|
(502
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes before effect of income tax settlements
|
|
$
|
117,510
|
|
|
$
|
63,995
|
|
|
$
|
56,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
34.4
|
%
|
|
|
32.5
|
%
|
|
|
35.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by
the IRS on a regular basis. The IRS is currently conducting audits of NPC for the years 1997-2004.
NPC believes that has adequately provided reasonable reserves for reasonable and foreseeable
outcomes related to uncertain tax matters.
151
The net deferred income tax liability consists of deferred income tax liabilities less related
deferred income tax assets, as shown (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Deferred income tax assets
|
|
|
|
|
|
|
|
|
|
Net operating loss and credit carryovers
|
|
$
|
137,344
|
|
|
$
|
129,420
|
|
|
Employee benefit plans
|
|
|
29,997
|
|
|
|
(530
|
)
|
|
Customer advances
|
|
|
21,014
|
|
|
|
34,320
|
|
|
Gross-ups received on contributions in aid of construction and customer advances
|
|
|
21,844
|
|
|
|
18,424
|
|
|
Deferred revenues
|
|
|
1,586
|
|
|
|
11,303
|
|
|
Provision for contract termination
|
|
|
(4
|
)
|
|
|
43,737
|
|
|
Other — net
|
|
|
14,207
|
|
|
|
12,797
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
225,988
|
|
|
|
249,471
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax assets associated with regulatory matters
|
|
|
|
|
|
|
|
|
|
Excess deferred income taxes
|
|
|
5,259
|
|
|
|
6,005
|
|
|
Unamortized investment tax credit
|
|
|
8,192
|
|
|
|
9,063
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
13,451
|
|
|
|
15,068
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets before valuation allowance
|
|
|
239,439
|
|
|
|
264,539
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
|
(732
|
)
|
|
|
(984
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets after valuation allowance
|
|
$
|
238,707
|
|
|
$
|
263,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
|
Excess of tax depreciation over book depreciation
|
|
$
|
345,135
|
|
|
$
|
349,056
|
|
|
Deferred energy
|
|
|
171,113
|
|
|
|
140,330
|
|
|
Regulatory assets
|
|
|
59,092
|
|
|
|
11,061
|
|
|
Other — net
|
|
|
43,299
|
|
|
|
28,169
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
618,639
|
|
|
|
528,616
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities associated with regulatory matters
|
|
|
|
|
|
|
|
|
|
Tax benefits flowed through to customers
|
|
|
153,471
|
|
|
|
155,304
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
153,471
|
|
|
|
155,304
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax liability
|
|
$
|
772,110
|
|
|
$
|
683,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liability
|
|
$
|
393,383
|
|
|
$
|
280,129
|
|
|
Net deferred income tax liability associated with regulatory matters
|
|
|
140,020
|
|
|
|
140,236
|
|
|
|
|
|
|
|
|
|
|
Total net deferred income tax liability
|
|
$
|
533,403
|
|
|
$
|
420,365
|
|
|
|
|
|
|
|
|
|
The
total 2006 net deferred income tax liability of $533,403 includes
$5,950 of deferred tax liability associated with accumulated
depreciation on the Mohave generating station, which, on the
financial statements, is included in regulatory assets. Reference
Note 13, Commitments and Contingencies, for further discussion of
the Mohave Generating Station.
NPC’s balance sheet contains a net regulatory asset of $140.0 million at December 31,
2006 and $140.2 million at December 31, 2005. The regulatory asset consists of future revenue to
be received from customers due to flow-through of the tax benefits of temporary differences and
goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future
revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist
of temporary differences for liberalized depreciation at rates in excess of current rates and
unamortized investment tax credits. The regulatory liability for temporary differences related to
liberalized depreciation will continue to be amortized using the average rate assumption method
required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused
by the investment tax credit will be amortized ratably in the same fashion as the accumulated
deferred investment credit.
As reflected in NPC’s balance sheet (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Tax benefits flowed through to customers
|
|
|
|
|
|
|
|
|
|
Related to property
|
|
$
|
55,177
|
|
|
$
|
54,371
|
|
|
Related to goodwill
|
|
|
98,294
|
|
|
|
100,933
|
|
|
|
|
|
|
|
|
|
|
Regulatory tax asset
|
|
|
153,471
|
|
|
|
155,304
|
|
|
|
|
|
|
|
|
|
|
|
|
Liberalized depreciation at rates in excess of current rates
|
|
|
5,259
|
|
|
|
6,005
|
|
|
Unamortized investment tax credits
|
|
|
8,192
|
|
|
|
9,063
|
|
|
|
|
|
|
|
|
|
|
Regulatory tax liability
|
|
|
13,451
|
|
|
|
15,068
|
|
|
|
|
|
|
|
|
|
|
Net regulatory tax asset
|
|
$
|
140,020
|
|
|
$
|
140,236
|
|
|
|
|
|
|
|
|
|
152
SPR and its subsidiaries file a consolidated federal income tax return. Current income
taxes are allocated based on SPR’s and each subsidiaries’ respective taxable income or loss and
investment tax credits as if each subsidiary filed a separate return.
SPR owes NPC $20.6 million
in inter-company tax payments.
The following table summarizes the tax NOL and credit carryforwards and associated
carryforward periods, and a valuation allowance for amounts which NPC has determined that
realization is uncertain (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
|
|
|
Type of Carryforward
|
|
Deferred Tax Asset
|
|
|
Valuation Allowance
|
|
|
Net Deferred Tax Asset
|
|
|
Period
|
|
|
Federal NOL
|
|
$
|
125,681
|
|
|
$
|
—
|
|
|
$
|
125,681
|
|
|
|
2020-2023
|
|
|
State NOL
|
|
|
9
|
|
|
|
—
|
|
|
|
9
|
|
|
|
2008
|
|
|
Research and
development credit
|
|
|
1,666
|
|
|
|
—
|
|
|
|
1,666
|
|
|
|
2021-2025
|
|
|
Alternative minimum tax credit
|
|
|
8,696
|
|
|
|
—
|
|
|
|
8,696
|
|
|
indefinite
|
|
Arizona coal credits
|
|
|
1,292
|
|
|
|
732
|
|
|
|
560
|
|
|
|
2007-2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
137,344
|
|
|
$
|
732
|
|
|
$
|
136,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2006, NPC has gross federal and state net operating loss carryforwards of
$359.1 million and $124 thousand, respectively.
Considering all positive and negative evidence regarding the utilization of NPC’s deferred tax
assets, it has been determined that NPC is more-likely-than-not to realize all recorded deferred
tax assets, except some of the Arizona coal credits. As such, these Arizona coal credits represent
the only valuation allowance that has been recorded as of December 31, 2006.
Sierra Pacific Power Company
The following reflects the composition of taxes on income (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Provision (benefit) for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
28,497
|
|
|
$
|
67,291
|
|
|
$
|
690
|
|
|
State
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
28,497
|
|
|
|
67,291
|
|
|
|
690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
2,464
|
|
|
|
(38,074
|
)
|
|
|
3,676
|
|
|
State
|
|
|
226
|
|
|
|
2,136
|
|
|
|
(708
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
2,690
|
|
|
|
(35,938
|
)
|
|
|
2,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of excess deferred taxes
|
|
|
(1,570
|
)
|
|
|
(1,345
|
)
|
|
|
(1,697
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of investment tax credits
|
|
|
(1,788
|
)
|
|
|
(1,629
|
)
|
|
|
(1,636
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
27,829
|
|
|
$
|
28,379
|
|
|
$
|
325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income statement classification of provision (benefit) for
income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
23,570
|
|
|
$
|
26,038
|
|
|
$
|
14,978
|
|
|
Other income
|
|
|
4,259
|
|
|
|
2,341
|
|
|
|
(14,653
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
27,829
|
|
|
$
|
28,379
|
|
|
$
|
325
|
|
|
|
|
|
|
|
|
|
|
|
|
153
The total income tax provision differs from amounts computed by applying the federal
statutory tax rate to income before income taxes for the following reasons (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Income from continuing operations
|
|
$
|
57,709
|
|
|
$
|
52,075
|
|
|
$
|
18,577
|
|
|
Total income tax expense
|
|
|
27,829
|
|
|
|
28,379
|
|
|
|
325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pretax income
|
|
|
85,538
|
|
|
|
80,454
|
|
|
|
18,902
|
|
|
Statutory tax rate
|
|
|
35
|
%
|
|
|
35
|
%
|
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal income tax expense (benefit) at statutory rate
|
|
|
29,938
|
|
|
|
28,159
|
|
|
|
6,616
|
|
|
Depreciation related to difference in cost basis for tax purposes
|
|
|
2,517
|
|
|
|
2,678
|
|
|
|
2,691
|
|
|
Allowance for funds used during construction — equity
|
|
|
(2,265
|
)
|
|
|
(574
|
)
|
|
|
(601
|
)
|
|
ITC amortization
|
|
|
(1,788
|
)
|
|
|
(1,629
|
)
|
|
|
(1,636
|
)
|
|
Goodwill
|
|
|
954
|
|
|
|
844
|
|
|
|
506
|
|
|
Pension benefit plan
|
|
|
338
|
|
|
|
(945
|
)
|
|
|
(3,684
|
)
|
|
Research and development credit
|
|
|
(2,097
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Other — net
|
|
|
232
|
|
|
|
(154
|
)
|
|
|
(217
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes before effect of income tax
settlements
|
|
$
|
27,829
|
|
|
$
|
28,379
|
|
|
$
|
3,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate before effects of income tax settlements
|
|
|
32.5
|
%
|
|
|
35.3
|
%
|
|
|
19.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Effects of income tax settlements
|
|
|
—
|
|
|
|
—
|
|
|
|
(3,350
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
$
|
27,829
|
|
|
$
|
28,379
|
|
|
$
|
325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
32.5
|
%
|
|
|
35.3
|
%
|
|
|
1.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by
the IRS on a regular basis. The IRS is currently conducting audits of SPPC for the years
1997-2004. During the first quarter of 2004, SPR reached tentative agreements with the IRS for
certain matters. As a result of the tentative agreements, SPPC recognized tax benefits which
increased net income by approximately $3.4 million in 2004. SPPC believes that it has adequately
provided reasonable reserves for reasonable and foreseeable outcomes related to uncertain tax
matters.
154
The net deferred income tax liability consists of deferred income tax liabilities less related
deferred income tax assets, as shown (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax assets
|
|
|
|
|
|
|
|
|
|
Net operating loss and credit carryforwards
|
|
$
|
6,233
|
|
|
$
|
6,127
|
|
|
Employee benefit plans
|
|
|
39,191
|
|
|
|
9,997
|
|
|
Customer advances
|
|
|
11,149
|
|
|
|
25,202
|
|
|
Gross-ups received on contributions in aid of construction and customer advances
|
|
|
9,269
|
|
|
|
7,438
|
|
|
Provision for contract termination
|
|
|
200
|
|
|
|
19,378
|
|
|
Other
|
|
|
7,761
|
|
|
|
6,658
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
73,803
|
|
|
|
74,800
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax assets associated with regulatory matters
|
|
|
|
|
|
|
|
|
|
Excess deferred income taxes
|
|
|
9,852
|
|
|
|
11,421
|
|
|
Unamortized investment tax credit
|
|
|
10,772
|
|
|
|
11,735
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
20,624
|
|
|
|
23,156
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets
|
|
$
|
94,427
|
|
|
$
|
97,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
|
Excess of tax depreciation over book depreciation
|
|
$
|
195,203
|
|
|
$
|
211,645
|
|
|
Deferred energy
|
|
|
21,540
|
|
|
|
40,158
|
|
|
Regulatory assets
|
|
|
41,346
|
|
|
|
9,079
|
|
|
Other
|
|
|
14,035
|
|
|
|
9,193
|
|
|
|
|
|
|
|
|
|
|
Subtotal deferred tax liabilities
|
|
|
272,124
|
|
|
|
270,075
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities associated with regulatory matters
|
|
|
|
|
|
|
|
|
|
Tax benefits flowed through to customers
|
|
|
109,699
|
|
|
|
93,957
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax liability
|
|
$
|
381,823
|
|
|
$
|
364,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liability
|
|
$
|
198,321
|
|
|
$
|
195,275
|
|
|
Net deferred income tax liability associated with regulatory matters
|
|
|
89,075
|
|
|
|
70,801
|
|
|
|
|
|
|
|
|
|
|
Total net deferred income tax liability
|
|
$
|
287,396
|
|
|
$
|
266,076
|
|
|
|
|
|
|
|
|
|
SPPC’s balance sheet contains a net regulatory asset of $89.0 million at December 31,
2006 and $70.8 million at December 31, 2005. The regulatory asset consists of future revenue to be
received from customers due to flow-through of the tax benefits of temporary differences and
goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future
revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist
of temporary differences for liberalized depreciation at rates in excess of current rates and
unamortized investment tax credits. The regulatory liability for temporary differences related to
liberalized depreciation will continue to be amortized using the average rate assumption method
required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused
by the investment tax credit will be amortized ratably in the same fashion as the accumulated
deferred investment credit.
155
As reflected in SPPC’s balance sheet (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax benefits flowed through to customers
|
|
|
|
|
|
|
|
|
|
Related to property
|
|
$
|
50,998
|
|
|
$
|
43,959
|
|
|
Related to goodwill
|
|
|
58,701
|
|
|
|
49,998
|
|
|
|
|
|
|
|
|
|
|
Regulatory tax asset
|
|
|
109,699
|
|
|
|
93,957
|
|
|
|
|
|
|
|
|
|
|
|
|
Liberalized depreciation at rates in excess of current rates
|
|
|
9,852
|
|
|
|
11,421
|
|
|
Unamortized investment tax credits
|
|
|
10,772
|
|
|
|
11,735
|
|
|
|
|
|
|
|
|
|
|
Regulatory tax liability
|
|
|
20,624
|
|
|
|
23,156
|
|
|
|
|
|
|
|
|
|
|
Net regulatory tax asset
|
|
$
|
89,075
|
|
|
$
|
70,801
|
|
|
|
|
|
|
|
|
|
SPR and its subsidiaries file a consolidated federal income tax return. Current income
taxes are allocated based on SPR’s and each subsidiaries’ respective taxable income or loss and
investment tax credits as if each subsidiary filed a separate return. Per the Company’s tax
sharing agreement, SPPC owes SPR $9.1 million in current taxes payable.
The following table summarizes the tax NOL and credit carryforwards and associated
carryforward periods for SPPC (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
|
|
|
Type of Carryforward
|
|
Deferred Tax Asset
|
|
|
Valuation Allowance
|
|
|
Net Deferred Tax Asset
|
|
|
Period
|
|
|
Federal NOL
|
|
$
|
5,184
|
|
|
$
|
—
|
|
|
$
|
5,184
|
|
|
|
2020-2023
|
|
|
State NOL
|
|
|
1,049
|
|
|
|
—
|
|
|
|
1,049
|
|
|
|
2010-2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,233
|
|
|
$
|
—
|
|
|
$
|
6,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2006, SPPC has gross federal and state net operating loss carryforwards
of $14.8 million and $11.9 million, respectively.
Considering all positive and negative evidence regarding the utilization of SPPC’s deferred
tax assets, it has been determined that the company is more-likely-than-not to realize all recorded
deferred tax assets and therefore no valuation allowance has been recorded as of December 31, 2006.
NOTE 11. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS
SPR has pension plans covering substantially all employees. Benefits are based on years of
service and the employee’s highest compensation for a period prior to retirement. SPR also has
other postretirement plans which provide medical and life insurance benefits for certain retired
employees. The following tables provide a reconciliation of benefit obligations, plan assets and
the funded status of the plans. This reconciliation is based on a September 30 measurement date
(dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
Change in benefit obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation, beginning of year
|
|
$
|
625,451
|
|
|
$
|
519,785
|
|
|
$
|
179,184
|
|
|
$
|
162,013
|
|
|
Service cost
|
|
|
23,033
|
|
|
|
18,481
|
|
|
|
3,533
|
|
|
|
3,281
|
|
|
Interest cost
|
|
|
36,627
|
|
|
|
32,248
|
|
|
|
10,283
|
|
|
|
9,858
|
|
|
Plan Participants’ contributions
|
|
|
—
|
|
|
|
—
|
|
|
|
1,445
|
|
|
|
1,180
|
|
|
Actuarial loss (gain)
|
|
|
(18,713
|
)
|
|
|
71,536
|
|
|
|
(10,770
|
)
|
|
|
10,258
|
|
|
Gross Benefits paid
|
|
|
(20,960
|
)
|
|
|
(20,257
|
)
|
|
|
(11,998
|
)
|
|
|
(8,112
|
)
|
|
less: federal subsidy on benefits paid
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
(515
|
)
|
|
|
—
|
|
|
Plan amendments
|
|
|
(65
|
)
|
|
|
2,935
|
|
|
|
—
|
|
|
|
695
|
|
|
Acquisitions/divestitures
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Special Termination Benefits
|
|
|
—
|
|
|
|
723
|
|
|
|
—
|
|
|
|
11
|
|
|
Curtailments
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Settlements
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation, end of year
|
|
$
|
645,373
|
|
|
$
|
625,451
|
|
|
$
|
171,162
|
|
|
$
|
179,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
156
The accumulated benefit obligation for Pension Benefits at the end of 2006 and 2005 was
$526 million and $504 million respectively.
The weighted-average actuarial assumptions used to determine end of year benefit obligations
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
|
Rate of compensation increase
|
|
|
4.50
|
%
|
|
|
4.50
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
In 2006, for measurement purposes, the assumed annual rate of increase in the per capita
cost of covered health care benefits was 8%, grading down to 5% in 2013.
In selecting an assumed discount rate for fiscal year 2006 pension cost, SPR considered the
yield on high quality bonds as measured by Moody’s Investors Service, Inc. (Moody’s) Aa composite
bond index. However, to select an assumed discount rate for fiscal year-end 2006 disclosures and
for fiscal year 2006 pension cost, SPR’s projected benefit payments were matched to the yield curve
derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th
percentiles of these bond yields.
Assumed health care cost trend rates have a significant effect on the amounts reported for the
health care plans. A one-percentage-point change in assumed health care cost trend rates would have
the following effect:
|
|
|
|
|
|
|
|
|
|
|
Effect on the postretirement benefit obligation
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
Effect of a 1-percentage point increase
|
|
$
|
18,823
|
|
|
$
|
21,237
|
|
|
Effect of a 1-percentage point decrease
|
|
$
|
(15,657
|
)
|
|
$
|
(17,410
|
)
|
The following table shows the change in plan assets for 2006 and 2005. SPR contributions
for the other post-retirement benefits reflect benefit payments made by SPR (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
Change in plan assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets, beginning of year
|
|
$
|
488,766
|
|
|
$
|
436,291
|
|
|
$
|
53,223
|
|
|
$
|
50,484
|
|
|
Adjustment to beginning of year value
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(1,766
|
)
|
|
Actual return on plan assets
|
|
|
34,424
|
|
|
|
55,706
|
|
|
|
8,015
|
|
|
|
386
|
|
|
Employer contributions
|
|
|
32,329
|
|
|
|
17,026
|
|
|
|
12,550
|
|
|
|
10,928
|
|
|
Plan participants’ contributions
|
|
|
—
|
|
|
|
—
|
|
|
|
1,445
|
|
|
|
1,303
|
|
|
Gross benefits paid
|
|
|
(20,960
|
)
|
|
|
(20,257
|
)
|
|
|
(11,998
|
)
|
|
|
(8,112
|
)
|
|
Acquisitions
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Special termination benefits
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Settlements
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Expenses paid
|
|
|
(299
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets, end of year
|
|
$
|
534,260
|
|
|
$
|
488,766
|
|
|
$
|
63,235
|
|
|
$
|
53,223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The asset allocation for SPR’s pension plans at the end of 2006 and 2005, and the target
allocation for 2007, by asset category, follows. The fair value of plan assets for these plans is
$534.2 million and $488.8 million, at the end of 2006 and 2005, respectively. The asset values are
determined using quoted market prices. The expected long-term rate of return on these plan assets
was 8.25% in 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target Allocation Percentage of Plan Assets at Year End
|
|
Asset Category
|
|
2007
|
|
2006
|
|
2005
|
|
Equity securities
|
|
|
60
|
%
|
|
|
60
|
%
|
|
|
60
|
%
|
|
Debt securities
|
|
|
39
|
|
|
|
39
|
|
|
|
39
|
|
|
Other
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
157
The asset allocation for the other postretirement benefit plans at the end of 2006 and
2005, and target allocation for 2007, by asset category, follows. The fair value of plan assets for
these plans is $63.2 million and $53.2 million at the end of 2006 and 2005, respectively. The asset
values are determined using recorded closing sales on a national securities exchange. The expected
long-term rate of return on these plan assets was 8.25% in 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target Allocation Percentage of Plan Assets at Year End
|
|
Asset Category
|
|
2007
|
|
2006
|
|
2005
|
|
Equity securities
|
|
|
60
|
%
|
|
|
60
|
%
|
|
|
60
|
%
|
|
Debt securities
|
|
|
39
|
|
|
|
39
|
|
|
|
39
|
|
|
Other
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR’s investment strategy is to ensure the safety of the principal of the assets and
obtain asset performance to meet the continuing obligations of the plan. SPR strives to maintain a
reasonable and prudent amount of risk, and seeks to limit risk through diversification of assets.
Also, SPR considers the ability of the plan to pay all benefit and expense obligations when due,
and to control the costs of administering and managing the plan. SPR’s investment guidelines
prohibit investing the plan assets in real estate and SPR’s own stock. Currently, the plan assets
are invested in international and domestic equity securities, and fixed securities which include
bonds.
The following table shows the funded status of each of the plans for 2006 and 2005 (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
Funded Status, end of year:
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
Fair value of plan assets
|
|
$
|
534,260
|
|
|
$
|
488,767
|
|
|
$
|
63,236
|
|
|
$
|
53,223
|
|
|
Benefit obligations
|
|
$
|
(645,373
|
)
|
|
$
|
(625,451
|
)
|
|
$
|
(172,192
|
)
|
|
$
|
(179,184
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status
|
|
$
|
(111,113
|
)
|
|
$
|
(136,684
|
)
|
|
$
|
(108,956
|
)
|
|
$
|
(125,961
|
)
|
|
Unrecognized net actuarial (gain)/loss
|
|
|
N/A
|
|
|
|
166,157
|
|
|
|
N/A
|
|
|
|
77,919
|
|
|
Unrecognized prior service (credit)/cost
|
|
|
N/A
|
|
|
|
14,543
|
|
|
|
N/A
|
|
|
|
1,228
|
|
|
Unrecognized net transition (asset)/obligation
|
|
|
N/A
|
|
|
|
—
|
|
|
|
N/A
|
|
|
|
6,405
|
|
|
Contribution between measurement date and
fiscal year end
|
|
|
368
|
|
|
|
15,332
|
|
|
|
—
|
|
|
|
4,101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount recognized, end of year
|
|
$
|
(110,745
|
)
|
|
$
|
59,348
|
|
|
$
|
(108,956
|
)
|
|
$
|
(36,308
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts for pension and postretirement benefits recognized in the consolidated balance
sheets consist of the following (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
Amounts recognized in the statement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of financial position consist of:
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
Noncurrent asset
|
|
$
|
—
|
|
|
|
N/A
|
|
|
$
|
—
|
|
|
|
N/A
|
|
|
Current liability
|
|
|
(1,482
|
)
|
|
|
N/A
|
|
|
|
—
|
|
|
|
N/A
|
|
|
Noncurrent liability
|
|
|
(109,263
|
)
|
|
|
N/A
|
|
|
|
(108,956
|
)
|
|
|
N/A
|
|
|
Prepaid benefit cost
|
|
|
N/A
|
|
|
$
|
75,769
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
Accrued benefit cost
|
|
|
N/A
|
|
|
|
(16,421
|
)
|
|
|
N/A
|
|
|
$
|
(36,308
|
)
|
|
Additional minimum liability
|
|
|
N/A
|
|
|
|
(7,950
|
)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
Intangible asset
|
|
|
N/A
|
|
|
|
15
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
Accumulated other comprehensive income
|
|
|
N/A
|
|
|
|
7,935
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
(110,745
|
)
|
|
$
|
59,348
|
|
|
$
|
(108,956
|
)
|
|
$
|
(36,308
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158
The following amounts would have been recognized in Accumulated Other Comprehensive
Income, net of taxes, according to the provisions of SFAS 158, which the Company adopted in 2006.
Since the Company is able to recover SFAS 87 and SFAS 106 expenses through rates, the amounts will
be recorded as Other Regulatory Assets under the provisions of SFAS 71.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
Amounts recognized as other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
regulatory assets:
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Net actuarial (gain)/loss
|
|
$
|
101,674
|
|
|
|
N/A
|
|
|
$
|
102,413
|
|
|
|
N/A
|
|
|
Prior service (credit)/cost
|
|
|
12,587
|
|
|
|
N/A
|
|
|
|
1,107
|
|
|
|
N/A
|
|
|
Transition (asset)/obligation
|
|
|
—
|
|
|
|
N/A
|
|
|
|
5,436
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
114,261
|
|
|
|
N/A
|
|
|
$
|
108,956
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The estimated amounts that will be amortized from other regulatory assets into net
periodic cost in 2007 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
Pension Benefits
|
|
|
Postretirement
|
|
|
|
|
|
|
|
Benefits
|
|
|
|
|
|
|
|
|
|
Actuarial (gain)/loss
|
|
$
|
7,184
|
|
|
$
|
3,259
|
|
|
Prior service (credit)/cost
|
|
|
1,629
|
|
|
|
122
|
|
|
Transition (asset)/obligation
|
|
|
—
|
|
|
|
969
|
|
At the end of 2006 and 2005, the projected benefit obligation, accumulated benefit
obligation, and fair value of plan assets for pension plans with a projected benefit obligation in
excess of plan assets, and pension plans with an accumulated benefit obligation in excess of plan
assets, were as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected Benefit Obligation Exceeds
|
|
|
Accumulated Benefit Obligation Exceeds
|
|
|
|
|
the
Fair Value of Plan’s Assets
|
|
|
the
Fair Value of Plan’s Assets
|
|
|
|
|
2006
|
|
2005
|
|
|
|
2006
|
|
2005
|
|
|
Projected benefit obligation, end of year
|
|
$
|
645,373
|
|
$
|
625,451
|
|
|
|
$
|
25,890
|
|
$
|
27,225
|
|
|
|
Accumulated benefit obligation, end of year
|
|
|
—
|
|
|
—
|
|
|
|
|
23,768
|
|
|
24,703
|
|
|
|
Fair value of plan assets, end of year
|
|
|
534,260
|
|
|
488,766
|
|
|
|
|
—
|
|
|
—
|
|
|
The accumulated postretirement benefit obligation exceeds plan assets for all of the
company’s other postretirement benefit plans.
The expected cash flows for the plans are as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
|
|
|
|
|
Company contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 (expected)
|
|
$
|
1,482
|
|
|
|
$12,465
|
|
|
|
|
|
Pension Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
|
|
|
|
|
|
|
|
Expected Federal
|
|
|
|
|
|
|
|
|
Gross
|
Subsidy
|
|
Expected benefit payments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
23,595
|
|
|
|
9,209
|
|
|
|
597
|
|
|
2008
|
|
|
24,903
|
|
|
|
9,812
|
|
|
|
670
|
|
|
2009
|
|
|
26,668
|
|
|
|
10,372
|
|
|
|
770
|
|
|
2010
|
|
|
28,684
|
|
|
|
11,028
|
|
|
|
853
|
|
|
2011
|
|
|
30,887
|
|
|
|
11,611
|
|
|
|
843
|
|
|
2012-2016
|
|
|
196,777
|
|
|
|
66,337
|
|
|
|
4,993
|
|
The above benefit payments are obligations of the indicated plan, and reflect payments
which do not include employee contributions. The expected benefit payment information that
reflects the employee obligation is almost exclusively paid from plan assets. A small portion of
the pension benefit obligation is paid from the plan sponsor’s assets.
159
The components of net periodic pension and other postretirement benefit costs for the
consolidated companies, SPPC and NPC are presented below (dollars in thousands):
Sierra Pacific Resources, consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
23,033
|
|
|
$
|
18,481
|
|
|
$
|
17,988
|
|
|
$
|
3,533
|
|
|
$
|
3,281
|
|
|
$
|
3,058
|
|
|
Interest cost
|
|
|
36,627
|
|
|
|
32,248
|
|
|
|
30,273
|
|
|
|
10,283
|
|
|
|
9,858
|
|
|
|
9,258
|
|
|
Expected return on plan assets
|
|
|
(40,729
|
)
|
|
|
(36,167
|
)
|
|
|
(30,632
|
)
|
|
|
(4,919
|
)
|
|
|
(3,862
|
)
|
|
|
(4,100
|
)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial (gain)/loss
|
|
|
9,778
|
|
|
|
6,454
|
|
|
|
8,971
|
|
|
|
4,614
|
|
|
|
3,782
|
|
|
|
4,129
|
|
|
Prior service (credit)/cost
|
|
|
1,892
|
|
|
|
1,714
|
|
|
|
1,714
|
|
|
|
122
|
|
|
|
63
|
|
|
|
63
|
|
|
Transition (asset)/obligation
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
969
|
|
|
|
969
|
|
|
|
969
|
|
|
Curtailment (gain)/loss
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Settlement (gain)/loss /
Special termination charges
|
|
|
—
|
|
|
|
723
|
|
|
|
—
|
|
|
|
—
|
|
|
|
11
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net benefit cost
|
|
$
|
30,601
|
|
|
$
|
23,453
|
|
|
$
|
28,314
|
|
|
$
|
14,602
|
|
|
$
|
14,102
|
|
|
$
|
13,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The average percentage of SPR net periodic costs capitalized during 2006, 2005 and
2004 was 35.5%, 34.1%, and 32.1%, respectively.
Nevada Power Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
12,900
|
|
|
$
|
10,328
|
|
|
$
|
9,770
|
|
|
$
|
1,052
|
|
|
$
|
887
|
|
|
$
|
798
|
|
|
Interest cost
|
|
|
17,466
|
|
|
|
15,064
|
|
|
|
13,824
|
|
|
|
2,105
|
|
|
|
1,977
|
|
|
|
1,892
|
|
|
Expected return on plan assets
|
|
|
(18,265
|
)
|
|
|
(16,025
|
)
|
|
|
(12,564
|
)
|
|
|
(1,079
|
)
|
|
|
(832
|
)
|
|
|
(885
|
)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial (gain)/loss
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
940
|
|
|
|
758
|
|
|
|
844
|
|
|
Prior service (credit)/cost
|
|
|
1,677
|
|
|
|
1,499
|
|
|
|
1,499
|
|
|
|
122
|
|
|
|
63
|
|
|
|
63
|
|
|
Transition (asset)/obligation
|
|
|
4,636
|
|
|
|
2,995
|
|
|
|
4,069
|
|
|
|
969
|
|
|
|
969
|
|
|
|
969
|
|
|
Curtailment (gain)/loss
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Settlement (gain)/loss /
Special termination charges
|
|
|
—
|
|
|
|
723
|
|
|
|
—
|
|
|
|
—
|
|
|
|
11
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net benefit cost
|
|
$
|
18,414
|
|
|
$
|
14,584
|
|
|
$
|
16,598
|
|
|
$
|
4,109
|
|
|
$
|
3,833
|
|
|
$
|
3,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The average percentage of NPC net periodic costs capitalized during 2006, 2005 and
2004 was 39.0%, 37.3%, and 33.7%, respectively.
Sierra Pacific Power Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
8,989
|
|
|
$
|
7,470
|
|
|
$
|
7,540
|
|
|
$
|
2,417
|
|
|
$
|
2,264
|
|
|
$
|
2,135
|
|
|
Interest cost
|
|
|
18,224
|
|
|
|
16,526
|
|
|
|
15,820
|
|
|
|
8,114
|
|
|
|
7,793
|
|
|
|
7,284
|
|
|
Expected return on plan assets
|
|
|
(21,617
|
)
|
|
|
(19,418
|
)
|
|
|
(17,558
|
)
|
|
|
(3,715
|
)
|
|
|
(2,929
|
)
|
|
|
(3,114
|
)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial (gain)/loss
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
3,646
|
|
|
|
2,994
|
|
|
|
3,252
|
|
|
Prior service (credit)/cost
|
|
|
212
|
|
|
|
212
|
|
|
|
213
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Transition (asset)/obligation
|
|
|
4,880
|
|
|
|
3,320
|
|
|
|
4,715
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Curtailment (gain)/loss
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Settlement (gain)/loss /
Special termination charges
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net benefit cost
|
|
$
|
10,688
|
|
|
$
|
8,110
|
|
|
$
|
10,730
|
|
|
$
|
10,462
|
|
|
$
|
10,122
|
|
|
$
|
9,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
160
The average percentage of SPPC net periodic costs capitalized during 2006, 2005
and 2004 was 33.3%, 32.1%, and 31.6%, respectively.
The weighted-average assumptions used to determine net periodic cost are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
|
|
Discount rate
|
|
|
5.75
|
%
|
|
|
6.10
|
%
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
|
|
6.10
|
%
|
|
|
6.00
|
%
|
|
Expected Return on Plan Assets
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.50
|
%
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
8.50
|
%
|
|
Rate of compensation increase
|
|
|
4.50
|
%
|
|
|
4.50
|
%
|
|
|
4.50
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
For measurement purposes, a 6% annual rate of increase in the per capita cost
of covered health care benefits was assumed for 2006. The rate was assumed to remain at 6% in all
future years.
The expected rate of return on plan assets was determined by considering a realistic
projection of what assets can earn, given existing capital market conditions, historical equity and
bond premiums over inflation, the effect of “normative” economic conditions that may differ from
existing conditions, and projected rates of return on reinvested assets.
The expected long-term rate of return on plan assets is 8.25% in 2007
.
The assumed health care cost trend rate has a significant effect on the amounts reported. A
one percentage point change in the assumed health care cost trend rate would have had the following
effect:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
One percentage point change:
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
Effect on total of service and interest cost components
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of a 1-percentage point increase in health care trend
|
|
|
1,669
|
|
|
|
1,872
|
|
|
|
1,845
|
|
|
Effects of a 1-percentage point decrease in health care trend
|
|
|
(1,360
|
)
|
|
|
(1,503
|
)
|
|
|
(1,486
|
)
|
There were no significant transactions between the plan and the employer or related
parties during 2006, 2005, or 2004.
NOTE 12. STOCK COMPENSATION PLANS
At December 31, 2006, SPR had several stock-based compensation plans, which are described
below.
SPR’s executive long-term incentive plan for key management employees, which was approved by
shareholders in May 2004, provides for the issuance of up to 7,750,000 of SPR’s common shares to
key employees through December 31, 2013. The plan permits the following types of grants,
separately or in combination: nonqualified and qualified stock options, stock appreciation rights,
restricted stock, performance units, performance shares, and bonus stock. During 2006, SPR issued
nonqualified stock options, restricted shares and performance shares under the long-term incentive
plan.
Non-Qualified Stock Options
Elected officers and key employees specifically designated by a committee of the Board of
Directors are eligible to be awarded nonqualified stock options (NQSO’s) based on the guidelines in
the plan. These grants are at 100% of the then current fair market value, and vest over different
periods, as stated in the grant. These options have to be exercised within ten years of award, and
no earlier than one year from the date of grant. At the time of grant, rights to dividend
equivalents may also be awarded.
The total number of nonqualifying stock options granted to all employees in 2006 was 176,416,
which were issued at an option price not less than market value at the date of grant. Of this
amount, 144,304 will vest over three years from the grant date at one-third per year, 30,000 will
vest one year from the date of grant, and the remaining 2,112 will vest only upon the restoration
of the quarterly common stock dividend within five years of the date of grant; otherwise, these
shares will expire unvested. The grants may be exercised for a period not exceeding ten years
from the grant date. The options may be exercised using either cash or previously acquired shares
valued at the current market price, or a combination of both. The Committee also allows cashless
exercises, subject to applicable securities law restrictions or other means consistent with the
purpose of the plan and the applicable law.
A summary of the status of SPR’s nonqualified stock option plan as of December 31, 2006, 2005,
and 2004, and changes during the year is presented below:
161
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
Exercise
|
|
|
|
|
|
|
Exercise
|
|
|
|
|
|
|
Exercise
|
|
|
Nonqualified Stock Options
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
Outstanding at beginning of year
|
|
|
1,077,772
|
|
|
$
|
14.38
|
|
|
|
1,227,950
|
|
|
$
|
15.91
|
|
|
|
1,371,869
|
|
|
$
|
16.33
|
|
|
Granted
|
|
|
176,416
|
|
|
$
|
13.29
|
|
|
|
169,036
|
|
|
$
|
10.10
|
|
|
|
45,000
|
|
|
$
|
7.29
|
|
|
Exercised
|
|
|
55,000
|
|
|
$
|
5.69
|
|
|
|
28,000
|
|
|
$
|
6.83
|
|
|
|
18,000
|
|
|
$
|
5.39
|
|
|
Forfeited
|
|
|
—
|
|
|
$
|
—
|
|
|
|
291,214
|
|
|
$
|
18.73
|
|
|
|
170,919
|
|
|
$
|
17.41
|
|
|
Outstanding at end of year
|
|
|
1,199,188
|
|
|
$
|
14.66
|
|
|
|
1,077,772
|
|
|
$
|
14.38
|
|
|
|
1,227,950
|
|
|
$
|
15.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intrinsic
value of options exercised
|
|
$
|
571,190
|
|
|
$
|
—
|
|
|
$
|
147,240
|
|
|
$
|
—
|
|
|
$
|
33,920
|
|
|
|
|
|
|
Fair value
of options vested
|
|
$
|
246,798
|
|
|
$
|
—
|
|
|
$
|
36,750
|
|
|
$
|
—
|
|
|
$
|
111,011
|
|
|
|
|
|
|
Options exercisable at year-end
|
|
|
943,085
|
|
|
$
|
15.25
|
|
|
|
928,368
|
|
|
$
|
15.07
|
|
|
|
1,215,450
|
|
|
$
|
15.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average grant date fair
value of options granted
1
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average of all grants for:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
$
|
4.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
$
|
5.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4.96
|
|
|
|
|
|
|
(1)
|
|
The fair value of each nonqualified option has been estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used for
grants issued in 2006, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
Average
|
|
Average
|
|
|
|
|
|
Dividend
|
|
Expected
|
|
Risk-
|
|
Average Expected
|
|
Year of Option Grant
|
|
Yield
|
|
Volatility
|
|
Free Rate of Return
|
|
Life
|
|
2006
|
|
|
0.00
|
%
|
|
|
27.06
|
%
|
|
|
4.51
|
%
|
|
6 years
|
|
2005
|
|
|
0.00
|
%
|
|
|
39.56
|
%
|
|
|
2.32
|
%
|
|
10 years
|
|
2004
|
|
|
0.00
|
%
|
|
|
52.60
|
%
|
|
|
4.79
|
%
|
|
10 years
|
The following table summarizes information about nonqualified stock options outstanding
at December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
Options Exercisable
|
|
|
|
Weighted
|
|
Number
|
|
|
|
|
|
|
|
|
|
Number Vested and
|
|
|
|
Average
|
|
Outstanding at
|
|
Remaining
|
|
Weighted Average
|
|
Exercisable at
|
|
Year of Grant
|
|
Exercise Price
|
|
12/31/06
|
|
Contractual Life
|
|
Exercise Price
|
|
12/31/06
|
|
1997
|
|
$
|
19.97
|
|
|
|
3,188
|
|
|
< 1 year
|
|
$
|
19.97
|
|
|
|
3,188
|
|
|
1998
|
|
$
|
24.93
|
|
|
|
15,840
|
|
|
1 years
|
|
$
|
24.93
|
|
|
|
15,840
|
|
|
1999
|
|
$
|
25.35
|
|
|
|
36,440
|
|
|
2 years
|
|
$
|
25.35
|
|
|
|
36,440
|
|
|
2000
|
|
$
|
16.00
|
|
|
|
400,000
|
|
|
2.6 - 3 years
|
|
$
|
16.00
|
|
|
|
400,000
|
|
|
2001
|
|
$
|
15.08
|
|
|
|
151,540
|
|
|
4 - 4.9 years
|
|
$
|
15.08
|
|
|
|
151,540
|
|
|
2002
|
|
$
|
14.05
|
|
|
|
241,360
|
|
|
5 - 5.9 years
|
|
$
|
14.05
|
|
|
|
241,360
|
|
|
2004
|
|
$
|
7.29
|
|
|
|
25,000
|
|
|
7.5 years
|
|
$
|
7.29
|
|
|
|
25,000
|
|
|
2005
|
|
$
|
10.10
|
|
|
|
149,404
|
|
|
8.2 - 8.4 years
|
|
$
|
10.10
|
|
|
|
69,717
|
|
|
2006
|
|
$
|
13.29
|
|
|
|
176,416
|
|
|
9.1 years
|
|
$
|
13.29
|
|
|
|
—
|
|
|
Weighted
Average Remaining Contractual Life
|
|
|
|
|
|
|
|
|
|
5.03 years
|
|
|
|
|
|
4.12 years
|
|
Intrinsic Value
|
|
$
|
3,136,677
|
|
|
|
|
|
|
|
|
$
|
1,975,871
|
|
|
|
Dividend
Equivalents were not granted for any of these awards.
162
Performance Shares
In 2006, 2005 and 2004, SPR granted performance shares in the following numbers and initial
values:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2/7/2006
|
|
|
2/7/2005
|
|
|
1/16/2004
|
|
|
|
|
|
|
Shares Granted
|
|
|
675,056
|
|
|
|
214,596
|
|
|
|
280,082
|
|
|
Value per Share
|
|
$
|
10.03
|
|
|
$
|
9.58
|
|
|
$
|
7.99
|
|
In 2006 and 2005, 172,446 and 171,676 shares of stock, respectively, were granted to plan
participants; the actual number of shares earned by each participant is dependent upon SPR
achieving certain financial goals over three-year performance periods. The value of all
performance share grants, if earned, will be equal to the market value of SPR’s common shares as of
the end of the performance periods. Sierra Pacific Resources, at its sole discretion, may pay
earned performance shares in the form of cash or in shares, or a combination thereof.
Also awarded in 2006 were 2,610 special grant shares to be earned only upon the restoration of
both the NPC and SPPC investment grade credit status within three years of the date of grant.
In August, 2006, upon the signing of an employment agreement for the Chief Executive Officer,
a grant of 500,000 performance shares was issued according to the agreement. The grant requires the
achievement of specific performance goals which were established in the agreement. The final
determination and approval of the number of shares awarded is at the discretion of the Board of
Directors and the Compensation Committee. In 2006, 65,000 shares were deemed to have been earned
and were issued.
Also granted in 2005, were 42,920 special grant shares to be earned only upon the restoration
of both the NPC and SPPC investment grade credit status within three years of the date of grant.
In 2004, SPR granted 280,082 shares of performance shares, which were subsequently
reclassified as restricted stock. These grants are included in the discussion below of Restricted
Stock.
SPR adopted SFAS 123R “Share Based Payment” in 2006, and according to the requirements set
forth in that standard, recognized expense in 2006 related to performance shares. For purposes of
determining 2006 expense, the compensation cost has been estimated using a lattice binomial pricing
model with the following assumptions used for 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
Average Risk-
|
|
Weighted
|
|
|
|
Average
|
|
Expected
|
|
Free Rate of
|
|
Average Fair
|
|
Year
|
|
Dividend Yield
|
|
Volatility
|
|
Return
|
|
Value
|
|
2006
|
|
|
0.00
|
%
|
|
|
39.03
|
%
|
|
|
4.57
|
%
|
|
$
|
13.93
|
|
The total
value of share based liabilities paid in 2006, 2005 and 2004 were
$1,447,300, $819,117 and $876,772, respectively. The total value of
shares vested in 2006, 2005 and 2004 were $2,046,124, $807,942 and
$0.00, respectively.
Restricted Stock Shares
In 2006, 5,643 shares of restricted stock were awarded at a grant price of $13.29 per share;
this grant was fully vested on December 31, 2006 and the shares were issued in early 2007.
There were no restricted shares granted in 2005.
In 2004, SPR granted 280,082 performance shares, which were subsequently reclassified as
restricted stock. Due to the achievement of certain performance goals established for this grant,
the number of shares available under this grant was increased to 297,587. This grant vested on
December 31, 2006, and 222,327 shares were issued in early 2007. The remaining 2004 grant of 3,700
163
restricted shares was issued at a grant price of $6.83 per share, and will vest over three years at
one-third per year. In 2005, the remaining 2,467 shares available under this grant were forfeited.
In 2003, SPR granted 448,576 shares of restricted stock at an average grant price of $5.93 per
share. Of the shares granted, 438,576 shares will vest over 4 years with one-third becoming
available in each of the years ended December 31, 2004, 2005 and 2006. The remaining 10,000
shares will vest over three years at one-third per year. In 2006, according to the vesting
schedule for each grant, 131,297 shares were issued under these grants.
A grant of 1,500 restricted shares was made in 2002, at a grant price of $7.35, vesting
equally over 4 years. In 2006, 375 shares were issued according to the terms of this grant.
The
total value of share based liabilities paid in 2006, 2005, and 2004
were $1,500,321, $1,405,724 and $301,111, respectively. The total
value of shares vested in 2006, 2005 and 2004 were $5,750,643,
$1,596,657 and $1,406,496, respectively.
Employee Stock Purchase Plan
Upon the inception of SPR’s employee stock purchase plan, SPR was authorized to issue up to an
aggregate of 400,162 shares of common stock to all of its employees with minimum service
requirements. On June 19, 2000, shareholders approved an additional 700,000 shares for distribution
under the plan. According to the terms of the plan, employees can choose twice each year to have up
to 15% of their base earnings withheld to purchase SPR’s common stock. The purchase price of the
stock is the lesser of 90% of the market value on the offering commencement date, or 100% of the
market value on the offering exercise date. Employees can withdraw from the plan at any time prior
to the exercise date. Under the plan SPR sold 55,954, 53,162 and 77,511 shares to employees in
2006, 2005 and 2004, respectively.
SPR adopted SFAS 123R “Share Based Payment” in 2006, and according to the requirements set
forth in that standard, recognized expense in 2006 related to the employee stock purchase plan.
For purposes of determining the 2006 expense and the 2005 & 2004 pro forma disclosures,
compensation cost has been estimated for the employees’ purchase rights on the date of grant, using
the Black-Scholes option-pricing model with the following assumptions used for 2006, 2005 and 2004,
with an option life of six months:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
Average
|
|
Risk-Free
|
|
Weighted
|
|
|
|
Dividend
|
|
Expected
|
|
Rate of
|
|
Average
|
|
Year
|
|
Yield
|
|
Volatility
|
|
Return
|
|
Fair Value
|
|
2006
|
|
|
0.00
|
%
|
|
|
19.73
|
%
|
|
|
4.95
|
%
|
|
$
|
2.62
|
|
|
2005
|
|
|
0.00
|
%
|
|
|
35.87
|
%
|
|
|
2.23
|
%
|
|
$
|
2.65
|
|
|
2004
|
|
|
0.00
|
%
|
|
|
52.60
|
%
|
|
|
1.79
|
%
|
|
$
|
2.24
|
|
NOTE 13. COMMITMENTS AND CONTINGENCIES (SPR, NPC and SPPC)
Purchased Power
The
utilities have several contracts for long-term purchase of electric energy. Expiration of
these contracts ranges from 2008 to 2027. Estimated future commitments under non-cancelable
agreements as of December 31, 2006 were as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Power
|
|
|
|
|
|
|
|
NPC
|
|
|
SPPC
|
|
|
SPR
(1)
|
|
|
2007
|
|
$
|
310,988
|
|
|
$
|
163,165
|
|
|
$
|
462,402
|
|
|
2008
|
|
|
257,739
|
|
|
|
125,161
|
|
|
|
368,810
|
|
|
2009
|
|
|
239,361
|
|
|
|
98,028
|
|
|
|
323,215
|
|
|
2010
|
|
|
244,305
|
|
|
|
93,836
|
|
|
|
323,882
|
|
|
2011
|
|
|
242,671
|
|
|
|
95,231
|
|
|
|
323,541
|
|
|
Thereafter
|
|
|
2,868,242
|
|
|
|
1,308,566
|
|
|
|
3,925,708
|
|
(1)
Amounts differ for SPR due to the elimination of certain
inter-company contracts.
164
Coal and Natural Gas
The Utilities have several long-term contracts for the purchase and transportation of coal and
natural gas. These contracts expire in years ranging from 2007 to 2023. Estimated future
commitments under non-cancelable agreements as of December 31, 2006 were as follows (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal and Gas
|
|
Transportation
|
|
|
|
NPC
|
|
SPPC
|
|
Total
|
|
NPC
|
|
SPPC
|
|
Total
|
|
2007
|
|
$
|
202,156
|
|
|
$
|
127,037
|
|
|
$
|
329,193
|
|
|
$
|
48,045
|
|
|
$
|
74,031
|
|
|
$
|
122,076
|
|
|
2008
|
|
|
26,019
|
|
|
|
26,919
|
|
|
|
52,938
|
|
|
|
36,814
|
|
|
|
58,099
|
|
|
|
94,913
|
|
|
2009
|
|
|
13,261
|
|
|
|
24,964
|
|
|
|
15,138
|
|
|
|
36,814
|
|
|
|
48,428
|
|
|
|
85,242
|
|
|
2010
|
|
|
10,293
|
|
|
|
—
|
|
|
|
10,293
|
|
|
|
36,814
|
|
|
|
48,418
|
|
|
|
85,232
|
|
|
2011
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
34,438
|
|
|
|
48,418
|
|
|
|
82,856
|
|
|
Thereafter
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
183,550
|
|
|
|
361,358
|
|
|
|
544,908
|
|
Long-Term Service Agreements
NPC entered into a long-term service agreement in December 2005 to perform maintenance on
generation units located at the Chuck Lenzie Generation Station. An additional long-term service
agreement was entered into in January 2006 for maintenance of the generation units at the
Silverhawk Generation Station. Future commitments under these agreements are as follows (dollars
in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long Term Service Agreements (1)
|
|
|
|
Lenzie
|
|
Silverhawk
|
|
Total
|
|
2007
|
|
$
|
11,258
|
|
|
$
|
4,721
|
|
|
$
|
15,979
|
|
|
2008
|
|
|
11,258
|
|
|
|
2,609
|
|
|
|
13,867
|
|
|
2009
|
|
|
11,258
|
|
|
|
13,009
|
|
|
|
24,267
|
|
|
2010
|
|
|
11,258
|
|
|
|
10,779
|
|
|
|
22,037
|
|
|
2011
|
|
|
9,062
|
|
|
|
3,086
|
|
|
|
12,148
|
|
|
Thereafter
|
|
|
90,340
|
|
|
|
33,443
|
|
|
|
123,783
|
|
(1)
Does not include equipment and services contracts related to the new
peaking units at Clark Generating Station.
Leases
SPPC has an operating lease for its general offices. The primary term of the lease is 25
years, ending 2010. The current annual rental is $5.4 million, which amount remains constant until
the end of the primary term. The lease has renewal options for an additional 50 years.
SPR’s, NPC’s and SPPC’s estimated future minimum cash payments, including SPPC’s headquarters
building, under non-cancelable operating leases as of December 31, 2006, were as follows (dollars
in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
|
|
|
NPC
|
|
|
SPPC
|
|
|
Total
|
|
|
2007
|
|
$
|
6,525
|
|
|
$
|
10,635
|
|
|
$
|
17,160
|
|
|
2008
|
|
|
7,146
|
|
|
|
10,297
|
|
|
|
17,443
|
|
|
2009
|
|
|
6,253
|
|
|
|
8,931
|
|
|
|
15,184
|
|
|
2010
|
|
|
5,161
|
|
|
|
7,587
|
|
|
|
12,748
|
|
|
2011
|
|
|
3,441
|
|
|
|
778
|
|
|
|
4,219
|
|
|
Thereafter
|
|
|
64,459
|
|
|
|
36,587
|
|
|
|
101,046
|
|
165
Environmental
Nevada Power Company
Reid Gardner Station
In August 1999, the Nevada Department of Environmental Protection (NDEP) issued a
discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be
closed or lined with impermeable liners over the following 10 years. This order also required
NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been
reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation
requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP which included
proposed dates for corrective action plans and/or suggested additional assessment plans for each
specified area. Any future ponds will be double-lined with inter-liner leak detection in
accordance with the NDEP Authorization to Discharge Permit issued October 2005.
Pond construction and lining costs to satisfy the NDEP order expended to date is approximately
$36 million. Expenditures for 2007 through 2010 are projected to be approximately $10 million.
In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit)
inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting
items and information pertaining to the sources identified in the Title V permit. NPC complied with
the request and any subsequent requests that followed. In September and October 2004, NPC met with
NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with
some elements of its Title V permit, and December 2004 issued Notices of Alleged Violation (NOAVs)
relating to record-keeping, monitoring and other alleged administrative infractions. Discussions
between NPC and NDEP ensued. In July 2005, NDEP issued new Notices of Alleged Violations (NOAVs).
In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2, 2004 and
address additional monitoring and reporting issues for the period September 2002 through December
2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring,
record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing
before the Nevada State Environmental Commission and then to judicial review. In July, 2005 NPC
received a letter from the Environmental Protection Agency (EPA) requiring submittal of information
relating to compliance of Reid Gardner Station with opacity emission limits and reporting
requirements. NPC has responded to the EPA information request. In June, 2006, the EPA issued a
Finding and Notice of Violation (NOV).
NPC has progressed to the final draft stage of dialogue and settlement discussions with NDEP,
EPA and Department of Justice (DOJ) regarding the NOVs and additional environmental controls and
equipment changes, environmental benefit projects, monetary penalties, and/or other measures that
may be required to achieve a settlement of the alleged violations. Management has booked an
estimated minimum liability with respect to these matters. Certain environmental controls and
equipment changes needed to assure compliance with existing or modified regulations were submitted
by NPC to the PUCN in NPC’s 2006 Integrated Resource Plan (IRP) filing. These expenditures were
approved by the PUCN in late 2006 and include equipment installation on the various units to
control startup opacity and particulates and reduce operating opacity and oxides of nitrogen.
Clark Station
In July 2000, NPC received a request from the EPA for information to determine the compliance
of certain generation facilities at NPC’s Clark Station with the applicable State Implementation
Plan. In November 2000, NPC and the DAQEM entered into a Corrective Action Order requiring, among
other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March
2001, the EPA issued an additional request for information that could result in remediation beyond
that specified in the November 2000 Corrective Action Order. In October 2003, the EPA issued a
violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the
EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the
alleged violations. In March 2004, the EPA issued another request for information regarding the
turbine blade upgrades, and NPC provided information responsive to this request in April and May
2004. NPC’s position is that a violation did not occur. In May 2006, the EPA, by letter from the
DOJ, notified NPC that it intends to initiate an enforcement action against NPC seeking unspecified
civil penalties, together with injunctive relief, for alleged violations of the Prevention of
Significant Deterioration requirements and Title V operating permit requirements of the Clean Air
Act. NPC has entered into ongoing dialogue and settlement discussions with the EPA and DOJ
regarding the alleged violations. Monetary penalties are not expected to be material and certain
environmental controls and equipment changes needed to assure compliance with existing or modified
regulations were submitted by NPC to the PUCN in January 2007 in NPC’s Second Amendment to the 2006
IRP filing.
NEICO
NEICO, a wholly owned subsidiary of NPC, owns property in Wellington, Utah, which was the site
of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond
of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes
is sufficient to cover reclamation costs. Management is continuing to evaluate various options
including reclamation and sale.
166
Sierra Pacific Power Company
PCB Treatment, Inc.
In September 1994, Region VII of the EPA notified SPPC that it was being named as a
potentially responsible party (PRP) regarding the past improper handling of Polychlorinated
Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and
the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material
to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB
Treatment, Inc.; however, the contaminated material was not disposed of, but remained on-site. A
number of the largest PRP’s formed a steering committee, which completed site investigations and
along with the EPA determined that the Sites should be remediated by removing the buildings to the
appropriate landfills. SPPC is a member of this steering committee. The cleanup has now been
completed on both buildings and are pending inspection and sign off by EPA. The cleanup for the
two buildings came in under budget, as such, SPPC does not expect any further obligations.
Litigation
Nevada Power Company and Sierra Pacific Power Company
Enron Litigation
Settlement Agreement
On February 1, 2006, the Utilities completed the settlement of long-term, ongoing litigation
involving Enron’s market manipulation during the Western United States energy crisis and Enron’s
claims with respect to terminated purchase power contracts between Enron Power Marketing Inc.
(“Enron”) and the Utilities in accordance with the terms of the Settlement Agreement, entered into
as of November 15, 2005 among the Utilities, Enron, and other related Enron affiliates (the
“Settlement Agreement”). The Settlement Agreement provided for the settlement and release of the
on-going litigation, regulatory proceedings, appellate proceedings, proofs of claim and other
claims between Enron and the Utilities related to these matters. The Settlement Agreement received
approval from the Enron Bankruptcy Court on December 15, 2005. The FERC’s approval of the
Settlement Agreement was received on January 25, 2006, which triggered the mutual releases and
discharges of all past, existing and future claims between the parties.
On January 26, 2006, upon final approval of the settlement with Enron, the Utilities paid
Enron approximately $129 million from available cash resources. On January 27, 2006, the
approximate $60 million cash held in escrow, plus interest, and NPC’s General and Refunding Series
H Bond of approximately $185.7 million and SPPC’s General and Refunding Series E Bond of
approximately $92.3 million were returned to the Utilities. As part of the settlement, NPC and
SPPC were granted general unsecured claims (the “Unsecured
Claims”) in Class Six of Enron’s Plan of Reorganization in the amount of $80.7 million and $45.8 million, respectively. On October 24,
2005, the Utilities purchased a put option from a major international banking institution that, if
exercised, obligated that institution to purchase the Unsecured Claims (contingent upon allowance
of the Unsecured Claims by the Bankruptcy Court), which ensured that the Utilities’ net cash outlay
to settle Enron’s claim would be no higher than $89.9 million. On February 16, 2006, the Unsecured
Claims were sold to a separate third party, resulting in a final net cash outlay which did not
materially differ from the anticipated cash outlay.
NPC and SPPC filed applications with the PUCN in January 2007 and December 2006, respectively,
to recover the amounts paid in connection with the Settlement Agreement, net of the proceeds from
the sale of the Unsecured Claims. The Utilities cannot predict, whether, to what extent or upon
what conditions the PUCN will approve recovery of these amounts. To the extent the Utilities
are not permitted to recover these costs through rate filings, the amounts not permitted would be
charged as a current operating expense. See Contract Termination
Liabilities.
Enron Bankruptcy Court Judgment
On June 5, 2002, Enron filed suit against the Utilities in its bankruptcy proceeding
before Enron Bankruptcy Court seeking liquidated damages of approximately $216 million
from NPC and $93 million from SPPC asserting the Utilities had not provided adequate assurance
of performance upon Enron’s demand, which triggered Enron to terminate all power contracts with the
Utilities under a Western Systems Power Pool Agreement (WSPPA). The Utilities denied
liability on numerous grounds, including wrongful termination, deceit and fraud in the
inducement, fraud, breach of contract, and unfair trade practices.
On September 26, 2003, the Bankruptcy Court entered summary judgment in favor of Enron (the
“Judgment”) for damages related to the termination of Enron’s power supply agreements with the
Utilities. The Judgment required NPC and SPPC to pay approximately $235 million and $103 million,
respectively, to Enron for liquidated damages and pre-judgment interest for power not delivered by
Enron under the power supply contracts terminated by Enron and approximately $17.7 million and $6.7
million, respectively, for power previously delivered to the Utilities. Based on the pre-judgment
rate of 12%, NPC and SPPC recognized
167
additional interest expense of $27.8 million and $12.4
million, respectively, in contract termination liabilities in the third quarter 2003. Also, NPC
and SPPC recorded additional contract termination liabilities for liquidated damages of $6.6
million and $2.1 million, respectively, in the third quarter of 2003. The Bankruptcy Court’s order
provided that until paid, the amounts owed by the Utilities would accrue interest post-Judgment at
a rate of 1.21% per annum.
On November 6, 2003, the Enron Bankruptcy Court ruled to stay execution of the Judgment
conditioned upon NPC and SPPC posting into escrow $235 million and $103 million, respectively, of
General and Refunding Mortgage Bonds plus approximately $282 thousand by NPC for pre-judgment
interest. On December 4, 2003, NPC and SPPC
complied with the order of the Bankruptcy Court by issuing NPC’s $235 million General and
Refunding Mortgage Bond, Series H and SPPC’s $103 million General and Refunding Mortgage Bond,
Series E into escrow along with the required cash deposit for NPC. Additionally, the Utilities were
ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and
SPPC, respectively, within 90 days from the date of the order, which would lower the principal
amount of General and Refunding Mortgage Bonds held in escrow by a like amount. The Utilities made
the payments as ordered on February 10, 2004. On April 16, 2004, NPC agreed to post an
additional cash sum of $25 million in escrow, which lowered the principal amount of NPC’s
General and Refunding Mortgage Bond, Series H, by a like amount, as part of an agreement with Enron
in which Enron agreed not to request any additional collateral from NPC or SPPC during the pendency
of the Utilities’ appeal of the Judgment to the District Court.
On October 10, 2004, in response to our appeal of the Bankruptcy Court Judgment, the U.S.
District Court for the Southern District of New York held that the pre-judgment interest should
have been calculated at the present value rate, rather than at the rate of 1% per month used by the
Bankruptcy Court. Based on this decision, the Utilities reversed the accrued interest included in
contract termination liabilities by approximately $40 million for the year ended 2004.
Nevada Power Company
Morgan Stanley Proceedings
On November 29, 2005, SPR and NPC entered into a settlement agreement with Morgan Stanley
Capital Group, Inc. (MSCG) resolving the litigation in the United States District Court, District
of Nevada concerning various power supply contracts between NPC and MSCG that had been terminated
by MSCG in April 2002 and the FERC 206 Complaint against MSCG and the related appeal described
above. Under the terms of the settlement agreement, NPC paid $17.5 million to MSCG and the parties
dismissed the litigation concerning terminated power contracts between them, and the FERC 206
proceedings as they relate to MSCG.
El Paso Merchant Energy
On January 19, 2006, NPC and EPME entered into a Settlement Agreement in resolution of their
termination claims and counterclaims under the WSPPA in the Federal District Court, District of
Nevada. Parties further agreed to withdraw, as to EPME, the appeal currently pending in the Ninth
Circuit (FERC 206 Appeal) and to dismiss, as to EPME, any complaints made at FERC related to such
appeal. NPC agreed to pay EPME $19 million. NPC and EPME executed a final written settlement
agreement implementing the terms of this settlement on February 13, 2006.
Nevada Power Company 2001 Deferred Energy Case
On November 30, 2001, NPC made a deferred energy filing with the PUCN seeking repayment for
purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, as
required by law. The application sought to establish a rate to repay purchased fuel and power
costs of $922 million and spread the recovery of the deferred costs, together with a carrying
charge, over a period of not more than three years.
On March 29, 2002, the PUCN issued its Order on the application, allowing NPC to recover $478
million over a three-year period, but disallowing $434 million of deferred purchased fuel and power
costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued
through September 2001 and $20.8 million in carrying charges accrued from October 2001 through
February 2002. The Order stated that the disallowance was based on alleged imprudence in incurring
the disallowed costs. NPC and the Bureau of Consumer Protection (BCP) both sought individual
review of the PUCN Order in the First District Court of Nevada. The District Court affirmed the
PUCN’s decision. Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.
On July 20, 2006, the Nevada Supreme Court ruled that NPC is allowed to recover approximately
$180 million of deferred energy and directed the District Court to remand the issue back to the
PUCN to determine the rate schedule that will be used to recover this amount. In all other
respects, the Nevada Supreme Court affirmed the District Court’s decision on the PUCN disallowance.
In the third quarter of 2006, as a result of the Nevada Supreme Court decision, NPC recorded
approximately $180 million
,
before tax
,
of the previously disallowed deferred energy costs in its
Consolidated Income Statements as “Reinstatement of Deferred Energy.”
168
In November 2006, the PUCN established a new docket (PUCN Docket No. 06-11029) for the purpose
of determining the appropriate rate schedule for recovering approximately $180 million of deferred
energy.
In February 2007, NPC entered into a stipulation where NPC shall be authorized to recover in
rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges.
This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed
stipulation related to the Western Energy Crisis, discussed in Note 3, Regulatory Actions. If the
PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties
will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
Peabody Western Coal Company
NPC owns an 11%, 255 MW interest in the Navajo Generating Station (Navajo) which includes
three coal-fired electrical generating units and is located in Northern Arizona. Other
participants in Navajo, are the Salt River Project (Salt River), Arizona Public Service Company,
Los Angeles Department of Water and Power, and Tucson Electric Power Company (together, the Joint
Owners).
On October 15, 2004, coal supplier Peabody Western Coal Co. (Peabody) filed a complaint
against the Joint Owners in Missouri State Court in St. Louis, seeking reimbursement of royalties
and other costs and damages for alleged breach of the coal supply agreement for the Navajo plant.
In January 2005, the Joint Owners were served and operating agent, Salt River, has engaged counsel
and is defending the suit on behalf of the Joint Owners. NPC believes Peabody’s claims are without
merit and intends to contest these.
On February 10, 2005, the Joint Owners filed Notice of Removal of the complaint to the U.
S. District Court, Eastern District of Missouri. On March 17, 2005, Peabody filed a motion to
remand the case back to state court in St. Louis, Missouri. Joint Owners have filed a motion to
dismiss the complaint for lack of jurisdiction. On May 30, 2006, the Federal District Court
granted Peabody’s motion and remanded the case back to state court. On June 29, 2006, Joint Owners
filed a new motion to dismiss with the Missouri state court and requested a stay of the discovery
proceedings pending the ruling on the new motion. On September 21, 2006, the Missouri state court
heard oral arguments on the motion to dismiss. Parties are in the process of completing briefing on
the motions. A decision is not expected until early 2007. Several discovery motions remain
pending. NPC is unable to predict the outcome of the decisions
.
Sierra Pacific Power Company
Farad Dam
SPPC owns 4 hydro generating plants (10.3 MW capacity) located in California that were to
be included in the sale of SPPC’s water business for $8 million to the Truckee Meadows Water
Authority (TMWA) in June 2001. The contract with TMWA requires that SPPC transfer the hydro assets
in working condition. However, one of the four hydro generating plants, Farad 2.8 MW, has been out
of service since the summer of 1996 due to a collapsed flume. While planning the reconstruction, a
flood on the Truckee River in January 1997 destroyed the diversion dam. The current estimate to
rebuild the diversion dam, if management decides to proceed, is approximately $20 million.
SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and
Zurich-American Insurance Company (Insurers) for the flume and dam. In December, 2003, SPPC sued
the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating
to potential rebuild costs. In May 2005, Insurers filed a motion for summary judgment on the
coverage issue, which has been denied. In October 2005, Insurers filed another (partial) summary
judgment motion with respect to coverage, which the court also denied. On June 16, 2006, Insurers
filed new summary judgment motions, which SPPC opposed. Management believes that it has a valid
insurance claim and is likely to recover the costs to rebuild the dam through the courts or from
other sources.
Management has not recorded a loss contingency for this matter, as the loss, if any, can not
be estimated at this time.
Piñon Pine
In its 2003 General Rate Case, SPPC sought recovery of its unreimbursed costs associated
with the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project
represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal
Technology initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund
50% of construction costs of the Project. SPPC’s participation in the Project had received PUCN
approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion
of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal
gasification unit never became fully operational. After numerous attempts to re-engineer the coal
gasifier, the technology was determined to be unworkable. In its order in May 2004, the PUCN
disallowed $43 million of unreimbursed costs associated with the Project. SPPC filed a Petition
for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004
(CV04-01434). In January 2006, the District Court vacated the PUCN’s disallowance in SPPC’s
169
2003
General Rate Case and remanded the case back to the PUCN for further review as to whether the costs
were justly and reasonably incurred (Order). On March 27, 2006, the PUCN appealed the Order to the
Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal
to the Supreme Court. On June 12, 2006, the District Court granted PUCN’s motion to stay the Order.
The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in
late December 2006, and on January 18, 2007 the matter was remitted back to the District Court,
which, consistent with its January 25, 2006 order, will remand the matter back to the PUCN for
further review. A procedural schedule for this review has not yet been established.
Other Legal Matters
SPR and its subsidiaries, through the course of their normal business operations, are
currently involved in a number of other legal actions, none of which, in the opinion of management,
is expected to have a significant impact on their financial positions, results of operations, or
cash flows.
Contract Termination Liabilities
At December 31, 2006 pursuant to the deferred energy accounting provisions of AB 369, included
in NPC and SPPC deferred energy balances were approximately $80.1 million and $16.3 million of
charges, respectively, for recovery in rates in future periods associated with the terminated power
supply contracts. In January 2007, NPC filed an application to recover $83.6 million in deferred
legal and settlement costs incurred to resolve claims arising for the western energy crisis. In
February 2007, NPC entered into a stipulation, with the parties to the case, to recover the $83.6
million plus carrying charges over a 3-year period beginning June 1, 2007. This stipulation is
expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related to
NPC’s 2001 Deferred Energy Case, discussed in Note 3, Regulatory Actions. If the PUCN does not
accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain
all rights to litigate. The PUCN has yet to issue an order on the stipulation.
In December 2006, SPPC filed an application to recover $22.6 million in deferred legal and
settlement costs incurred to resolve claims arising for the western energy crisis. To the extent
that the
Utilities are not permitted to recover any portion of these costs, the disallowed amounts
would be charged to current operating expense. In February 2007, SPPC entered into a stipulation
where SPPC replaces its request to implement rates on July 1, 2007 with a request to establish a
regulatory asset to recover the costs. SPPC further requests authority to recover carrying charges
on the regulatory asset. SPPC may request authority to begin recovering the regulatory asset
established by the PUCN in a future application to change rates. The parties to the stipulation
have requested that the PUCN issue an order by September 30, 2007. A significant disallowance of
these costs by the PUCN could have a material effect on the future financial position, results of
operations, and cash flows of SPR, NPC, and SPPC.
Regulatory Contingencies
Nevada Power Company
Mohave Generation Station (Mohave)
In 2005, NPC’s ownership interest in Mohave comprised approximately 10% of NPC’s peak
generation capacity. Southern California Edison (SCE) is the operating partner of Mohave and NPC
owns approximately 14% of the facility.
When operating, Mohave obtained all of its coal supply from a mine in northeast Arizona
on lands of the Navajo Nation and the Hopi Tribe (the “Tribes”). This coal was delivered from the
mine to Mohave by means of a coal slurry pipeline, which requires water that is obtained from
groundwater wells located on lands of the Tribes in the mine vicinity.
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court,
District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generation
Station (Mohave), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide
and particulates. An additional plaintiff, National Parks and Conservation Association, later
joined the suit. In 1999, the plant owners and plaintiffs filed a settlement with the court, which
resulted in a consent decree, approved by the court in November 1999. The consent decree
established emission limits for sulfur dioxide and opacity and required installation of air
pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter. Pursuant to the
decree, Mohave Units 1 and 2 ceased operations as of January 2006 as the new emission limits were
not met. Due to the lack of resolution regarding continual availability of the coal and water
supply with the Tribes, the Owners did not proceed with the Consent Decree.
In December 2005, the Owners of the Mohave plant suspended operation, pending resolution
of these issues. However, in June 2006, majority stake holder SCE announced it would no longer
participate in the efforts to return the plant to service. As a result, NPC decided it is not
economically feasible to continue its participation in the project. In September 2006, Salt
River’s co-tenancy agreement and the operating agreement between the Owners expired in July 2006.
The Owners are negotiating an extension of both agreements including a process that addresses how
Owners may sell or assign their right, title, interest and obligations in Mohave.
170
In NPC’s 2003 General Rate Case, the PUCN ordered the use of a regulatory asset to accumulate
the costs and savings associated with Mohave in the event of its shutdown with recovery of any
accumulated costs in a future rate case proceeding. NPC continues to recover the cost of Mohave in
rates, as such, associated savings are currently recorded as a reduction in electric operating
revenues-other. NPC continues to accumulate all costs and savings associated with the shut down of
Mohave, including
unrecovered plant costs, in Other
Regulatory Assets which has a balance of $17.8 million as of December 31, 2006. In its
general rate case, NPC requested further clarification on the regulatory treatment of Mohave. In
the event any portion of Mohave is disallowed, NPC will have to evaluate the asset for impairment.
NOTE 14. COMMON STOCK AND OTHER PAID-IN CAPITAL
Rights Agreement
In December 2005, the Board of Directors of SPR (the Board) voted to amend the Rights
Agreement, dated as of February 2001 (as amended and restated, the “Rights Agreement”), between the
SPR and Wells Fargo Bank Minnesota, N.A., to accelerate the final expiration date of the rights
(“Rights”) issued there under to December 2005, and to terminate the Rights Agreement upon the
expiration of the Rights. The Board also adopted a policy governing future entry into a
shareholder rights agreement or similar agreement (a “shareholder rights plan”). SPR’s policy is
to seek shareholder approval prior to the adoption of a shareholder rights plan, unless the board,
in the exercise of its fiduciary duties and with the concurrence of a majority of its independent
members, determines that, under the circumstances existing at the time, it is in the best interest
of SPR’s shareholders to adopt a shareholder rights plan without first obtaining shareholder
approval. If a shareholder rights plan is adopted without prior shareholder approval, the plan
must provide that is shall expire, unless ratified by shareholders, within one year of adoption.
Employee Stock Ownership Plans
As of December 31, 2006, 8,279,478 shares of common stock were reserved for issuance under the
Common Stock Investment Plan (CSIP), Employees’ Stock Purchase Plan (ESPP), and Executive Long-Term
Incentive Plan (LTIP).
The 2005 LTIP for officers and key employees allows for the issuance of SPR’s common shares
through December 2013, which can be earned and issued prior to December 2013. This Plan permits the
following types of grants, separately or in combination: nonqualified and qualified stock options;
stock appreciation rights; restricted stock; performance units; performance shares, bonus stock and
cash.
SPR also provides an ESPP to all of its employees meeting minimum service requirements.
Employees can choose twice each year (offering date) to have up to 15% of their base earnings
withheld to purchase SPR common stock. The purchase price of the stock is 90% of the market value
on the offering date or 100% of the market price on the execution date, if less.
The Non-employee Director Stock Plan provides that a portion of SPR’s outside directors’
annual retainer be paid in SPR common stock. SPR records the costs of these plans in accordance
with Accounting Principles Board Opinion No. 25. In addition, in 1996 SPR eliminated its outside
director retirement plan and converted the present value of each director’s vested retirement
benefit to phantom stock based on the stock price at the time of conversion. Phantom stock earns
dividends, also payable in phantom stock, which are recorded in each Director’s phantom account.
The value of these accounts is issued in stock or cash, at the election of the Board, at the time
the Director leaves the Board.
Non-Employee Director Stock
The annual retainer for non-employee directors is $57,000, and the minimum amount to be paid
in SPR stock is $35,000 per director. During 2006, 2005, and 2004, SPR granted the following total
shares and related compensation to directors in SPR stock, respectively: 30,733, 31,631, and 18,740
shares, and $154,000, $176,000, and $140,000.
Convertible Notes Issuance
In February 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010.
In August 2003, SPR obtained shareholder approval to issue additional shares of SPR’s common stock
in lieu of paying the cash payment component upon conversion of the Convertible Notes. In August
2005, SPR announced an offer to pay a cash premium to induce holders to convert their 7.25% Notes
to shares of SPR common stock. The conversion offer was accepted by 100% of the holders. In
September 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares, were
issued to the holders in exchange for the 7.25% Notes. For additional information regarding these
Convertible Notes see Note 6, Long-Term Debt.
In September 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional
shares and an aggregate of $54 million in cash consideration were paid to the holders in exchange
for the Convertible Notes. In accordance with SFAS No. 84, “Induced Conversion of Convertible
Debt,” the $54 million cash payment was expensed during the third quarter of 2005.
171
Stock Exchange Transactions
In November 2005 SPR issued 17,344,183 shares of common stock, along with cash in lieu of
fractional shares in connection with its PIES. Each PIES consisted of a forward stock purchase
contract and a senior unsecured note issued by SPR.
In February 2003, SPR acquired 2,095,650 of PIES including approximately $104.8 million of
7.93% Senior Notes that were a component of the PIES, in exchange for 13,662,393 shares of its
common stock.
In May 2005, SPR exchanged approximately 41% of the PIES for newly issued PIES (“New PIES”)
and issued, as a component of the New PIES $99,142,000 aggregate principal amount of 7.93% Senior
Notes, due 2007. These senior notes replaced the notes associated with the PIES. SPR successfully
remarketed these notes in June 2005 at an interest rate of 7.803%.
In August 2005, the remaining $141,076,000 aggregate principal amount of its 7.93% Senior
Notes associated with the PIES were remarketed. In August 2005, SPR used a portion of the proceeds
from the $225 million 6.75% Senior Notes (see Note 6, Long-Term Debt) to purchase all of the 7.93%
Senior Notes.
In November 2005, the purchase contract settlement date for the PIES and New PIES, 3.6101
shares per forward purchase contract were exchanged for a total of 17,344,183 shares of common
stock issued to holder of the PIES and New PIES.
Increased Authorized Shares
In May 2006, SPR’s shareholders approved an amendment to SPR’s Restated Articles of
Incorporation to increase the number of authorized shares of SPR common stock by 100,000,000 shares
for a total amount of 350,000,000 authorized shares.
Common Stock Offering
In August 2006, SPR issued 20 million shares of its $1 par value common stock. Net proceeds
from the issuance were $280.6 million. In August 2006, SPR contributed capital to NPC of
approximately $200 million. NPC used the proceeds to repay indebtedness under its revolving credit
facility.
In December 2006, SPR contributed capital to SPPC of approximately $75 million. SPPC used the
proceeds to repay indebtedness under its revolving credit facility and general corporate purposes.
SPR has invested the remaining proceeds in highly liquid short-term investments pending their use
for general corporate purposes. As of December 31, 2006 SPR has 350 million shares of common
stock authorized and 221.0 million shares of common stock issued and outstanding.
NOTE 15. PREFERRED STOCK
Sierra Pacific Power Company
Preferred Stock
In June 2006, SPPC redeemed $50 million of its Class A, Series 1 Preferred Stock. Two million
shares of stock were redeemed at a redemption price per share of $25.683, plus accrued dividends at
the redemption date of $0.4875 per share.
SPPC’s Restated Articles of Incorporation, as amended in August 1992, authorize an aggregate
amount of 11,780,500 shares of preferred stock at any given time.
On November 1, 2006, Sierra Pacific Power Company filed its restated articles of
incorporation with the Nevada Secretary of State. SPPC also filed a withdrawal of the certificate
of designation for its’ previously issued but no longer outstanding series of preferred stock.
The restated articles authorize the issuance of (i) Twenty million (20,000,000) shares of
common stock with a par value of $3.75 per share; and (ii) Ten million (10,000,000) shares of
preferred stock with no par value per share. Currently, all of SPPC’s one thousand (1,000) shares
of common stock outstanding are held by SPR.
Under the restated articles, preferred stock may be issued from time to time in one or more
series in such amounts and with such terms and conditions as may be determined by the board of
directors.
The restated articles limit the liability of directors and officers to the fullest extent
permitted by applicable law. The restated articles may be amended or altered by a vote of the
holders of a majority of SPPC’s common stock then issued, outstanding and entitled to vote. SPPC
may sell its assets upon the affirmative vote of a majority of the board of directors.
172
The restated articles eliminate the restrictive covenants that were previously contained
in SPPC’s articles of incorporation, including a limitation on the amount of dividends that may be
paid on SPPC’s common stock and a limitation on the amount of secured debt that may be issued by
SPPC.
The following table indicates the dollar amount and number of shares of SPPC preferred stock
outstanding at December 31 of each year (dollars in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
|
|
|
Shares Outstanding
|
|
|
Preferred Stock
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Not subject to mandatory
redemption SPPC Class A
Series 1
|
|
$
|
—
|
|
|
$
|
50,000
|
|
|
|
—
|
|
|
|
2,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Preferred Stock
|
|
$
|
—
|
|
|
$
|
50,000
|
|
|
|
—
|
|
|
|
2,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 16. EARNINGS PER SHARE (EPS) (SPR)
The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive
common shares resulting from stock options, the employee stock purchase plan, performance and
restricted stock plans, and the non-employee director stock plan.
For the year ended December 2004, SPR had outstanding $300 million in 7.25% convertible notes
due 2010 that were entitled to receive (non-cumulative) dividend payments on a 1:1 basis for
dividends paid to common shareholders without exercising the conversion option. These convertible
notes met the criteria of a participating security in the calculation basic EPS, and were
convertible at the option of the holders into 65,749,110 common shares.
Emerging Issues Task Force, Participating Securities and the Two-Class Method under FASB
Statement No. 128, (EITF 03-6) requires companies to use the “two-class” method to calculate basic
EPS, and the “if-converted” method to calculate diluted EPS if the result was dilutive. In
September 2005 SPR issued approximately 65.7 million shares of common stock in connection with the
early conversion of the 7.25% Convertible Notes. The weighted average shares outstanding up to the
date of conversion are shown separately for the year ending December 2005.
In November 2005 the conversion of SPR’s PIES resulted in the issuance of 17.3 million shares.
For the year ended December 2005 these shares are included in the denominator on a weighted
average basis.
173
The following table outlines the calculation for earnings per share (EPS):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Basic EPS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator ($000)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
279,792
|
|
|
$
|
86,137
|
|
|
$
|
30,842
|
|
|
Gain on sale of discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,629
|
|
|
|
|
Net income applicable to common stock
|
|
$
|
277,451
|
|
|
$
|
62,198
|
|
|
$
|
18,310
|
|
|
Net income applicable to convertible notes
|
|
$
|
—
|
|
|
$
|
20,039
|
|
|
$
|
10,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income used for basic calculation
|
|
$
|
277,451
|
|
|
$
|
82,237
|
|
|
$
|
28,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
208,531,134
|
|
|
|
140,334,552
|
|
|
|
117,331,365
|
|
|
Shares from conversion of notes
|
|
|
—
|
|
|
|
45,213,762
|
|
|
|
65,749,110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
208,531,134
|
|
|
|
185,548,314
|
|
|
|
183,080,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Share Amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
1.34
|
|
|
$
|
0.46
|
|
|
$
|
0.17
|
|
|
Gain on sale of discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common stock
|
|
$
|
1.33
|
|
|
$
|
0.44
|
|
|
$
|
0.16
|
|
|
Net income applicable to convertible notes
|
|
$
|
—
|
|
|
$
|
0.44
|
|
|
$
|
0.16
|
|
|
Diluted EPS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator ($000)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
279,792
|
|
|
$
|
86,137
|
|
|
$
|
30,842
|
|
|
Gain on sale of discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common stock
|
|
$
|
277,451
|
|
|
$
|
82,237
|
|
|
$
|
28,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding before dilution
|
|
|
208,531,134
|
|
|
|
140,334,552
|
|
|
|
117,331,365
|
|
|
Stock options
|
|
|
91,119
|
|
|
|
47,255
|
|
|
|
24,949
|
|
|
Executive long term incentive plan – restricted
|
|
|
113,456
|
|
|
|
187,810
|
|
|
|
242,679
|
|
|
Non-Employee Director stock plan
|
|
|
30,754
|
|
|
|
21,193
|
|
|
|
15,028
|
|
|
Employee stock purchase plan
|
|
|
3,345
|
|
|
|
3,925
|
|
|
|
15,028
|
|
|
Performance Shares
|
|
|
251,088
|
|
|
|
124,007
|
|
|
|
22,144
|
|
|
Convertible Stock
|
|
|
—
|
|
|
|
45,213,762
|
|
|
|
65,749,110
|
|
|
|
|
|
|
|
|
|
209,020,896
|
|
|
|
185,932,504
|
|
|
|
183,400,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Share Amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
1.34
|
|
|
$
|
0.46
|
|
|
$
|
0.17
|
|
|
Gain on sale of discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common stock
|
|
$
|
1.33
|
|
|
$
|
0.44
|
|
|
$
|
0.16
|
|
|
|
|
|
|
(1)
|
|
The denominator does not include stock equivalents resulting from the options
issued under the Nonqualified stock option plan for the years ended December 31, 2006,
2005, and 2004, due to conversion prices being higher than market prices for all
periods. Under the nonqualified stock option plan for the years ended December 31,
2006, 2005, and 2004, 932,946, 917,623 and 1,146,728 shares, respectively, would be
included. The denominator also does not include stock equivalents resulting from the
conversion of the Corporate PIES, for the year ended December 31, 2004. The amounts that
would be included in the calculation, if the conversion price were met would be 17.3
million shares.
|
174
NOTE 17. DISCONTINUED OPERATIONS AND DISPOSAL AND IMPAIRMENT OF LONG-LIVED ASSETS
Effective January 2002, SPR, NPC and SPPC adopted SFAS No. 144, “Accounting for the Impairment
or Disposal of Long-Lived Assets”, which addresses financial accounting and reporting for the
impairment or disposal of long-lived assets. SFAS No. 144 requires a component of an entity that
either has been disposed of or is classified as held for sale to be reported as discontinued
operations if certain conditions are met. Further, SFAS No. 144 requires that assets to be held and
used be tested for recoverability whenever events or circumstances indicate that its carrying
amount may not be recoverable.
Sierra Pacific Communications
SPC was formed as a Nevada corporation in 1999 to identify and develop business opportunities
in telecommunications services and infrastructure. SPC’s business activities have included the
development of a fiber optic system extending between Salt Lake City, Utah and Sacramento,
California (Long Haul Assets) and the development of Metro Area Networks (MAN) in Las Vegas and
Reno, Nevada.
In 2004, SPC disposed of their MAN assets and recognized a gain on sale of assets of
approximately $2.5 million (pretax) in connection with the sale of the MAN assets. SPC retained
possession of one duct and associated occupancy rights in the Long Haul System allowing SPC to
complete the transfer and sale of this duct, which was negotiated under a 2002 contract with Qwest
Communications (Qwest) for $20 million. In 2004, in accordance with Statement of Financial
Accounting Standards 144 (SFAS 144), Accounting for the Disposition or Impairment of Long-Lived
Assets, SPR reported the remaining Long Haul System as discontinued
operations. However, due to certain legal issues, SPR was delayed in consummating the sale
of the Long Haul System to Qwest. In January 2007 SPC agreed to dismiss pending arbitration
against Qwest. As part of the Settlement Agreement, Qwest agreed to execute a quit claim deed
disclaiming any further interest in the Long Haul system. In accordance with SFAS 144 if at any
time the criteria for classifying assets as held for sale are no longer met, a long-lived asset
classified as held for sale shall be reclassified as held and used. As of December 31, 2006, SPC
assets associated with the Long-Haul were reclassified for all periods presented from assets held
for sale in Discontinued Operations to assets held and used.
NOTE 18. GOODWILL AND OTHER MERGER COSTS
In March 2004, the PUCN issued a decision on NPC’s general rate case that included the
recovery of goodwill and other merger costs allocated to NPC resulting from the merger of SPR and
NPC in 1999. In its decision, the PUCN affirmed that NPC demonstrated merger savings exceeded
merger costs, the requisite requirement for recovery of goodwill and merger costs through rates
charged to NPC customers. The PUCN decision permits NPC to recover approximately $4 million per
year for two years beginning April 2004, based on a forty-year amortization of NPC’s total
goodwill. The amount recovered over those two years reflected a reduction of 20% from the amounts
sought by NPC, or approximately $1 million per year, due to customer satisfaction survey results
that the PUCN determined required improvement. As a result of the PUCN decision, goodwill of
approximately $198 million was reclassified as a regulatory asset and then transferred from the
financial statements of SPR to the financial statements of NPC as of March 31, 2004.
Furthermore, the PUCN decision requires NPC to again demonstrate in its next general rate
application that merger savings continue during the test period in that case. The PUCN’s order in
that case will determine if any further documentation of merger savings is required in the future.
In November 2006 NPC filed its GRC, requesting 100% recovery of the amortization amount.
Management expects that it will be able to demonstrate continued savings as a result of the merger
as well as satisfactory customer survey results.
In May 2004, the PUCN approved a settlement agreement entered into by SPPC, the Staff of the
PUCN and other interveners in connection with SPPC’s 2003 general rate case that permits SPPC
recovery of goodwill and other merger costs assigned to SPPC’s electric business. SPPC is
permitted to recover approximately $2.4 million per year for two years beginning June 2004, based
on a forty-year amortization of goodwill costs. As a result of the PUCN decision, goodwill of
approximately $96 million was reclassified to a regulatory asset and transferred from the financial
statements of SPR to the financial statements of SPPC as of June 30, 2004.
Similar to the decision reached in NPC’s rate case described above, in order to continue to
recover goodwill costs SPPC was required to again demonstrate in its next general rate application
filed October 2005, that merger savings continued during the test period in that case. In April
2006, the PUCN concluded that SPPC shall be allowed full recovery of its unamortized merger costs
thereby ending the merger-related regulatory filings. See Note 3, Regulatory Actions for more
information regarding the NPC and SPPC general rate decisions.
SFAS No. 142 provides that an impairment loss is to be recognized if the carrying value of
each reporting unit’s goodwill exceeds its fair value. For purposes of testing goodwill for
impairment, a discounted cash flow model was developed for NPC’s and SPPC’s electric business and
for SPR’s unregulated businesses to determine the fair value of each reporting unit as of March 31,
2004. As part of the impairment testing analysis, management revised certain underlying
assumptions utilized in previously performed preliminary analyses, that included, revised cash flow
forecasts, an increase in the discount rate applied to future cash flows and other
175
assumptions
related to the outcomes of NPC’s and SPPC’s general rate cases. As a result of this impairment
testing, SPR recorded a goodwill impairment charge related to NPC’s and SPPC’s electric reporting
units of approximately $2 million and $10 million as a charge to other operating expenses in SPR’s,
NPC’s and SPPC’s Consolidated Statements of Income for the quarter ended March 31, 2004.
Goodwill assigned to SPR’s unregulated businesses was determined not to be impaired.
In April 2006, the PUCN issued a decision on SPPC’s general rate case for the gas distribution
business that included the recovery of goodwill and other merger costs allocated to SPPC resulting
from the merger of SPR and NPC in 1999. In its decision, the PUCN affirmed that SPPC demonstrated
merger savings exceeded merger costs, the requisite requirement for recovery of goodwill and merger
costs. As a result of the PUCN decision, goodwill of approximately $18.9 million was reclassified
as a regulatory asset and transferred from the financial statements of SPR to the financial
statements of SPPC as of June 30, 2006. See Note 3 of the Notes to Consolidated Financial
Statements, Regulatory Actions for more information regarding the SPPC general rate decision.
Approximately $4 million of goodwill was assigned to SPR’s unregulated operations, (TGPC and
LOS) as of March 2006. In December 2006, TGPC sold its
investment in TGTC. As a result
of the sale, the $3.5 million of goodwill assigned to TGPC goodwill was allocated against the gain
on the sale of the investment. Reference Note 4, Investments in Subsidiaries and Other Property
for further discussion regarding the sale of TGTC. As of December 31, 2006, goodwill of
approximately $500 thousand is allocated to SPR’s unregulated operation of LOS.
NOTE 19. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following figures are unaudited and include all adjustments necessary in the opinion of
management for a fair presentation of the results of interim periods. Dollars are presented in
thousands except per share amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SIERRA PACIFIC RESOURCES
|
|
|
|
|
2006 Quarter Ended
|
|
|
|
|
Revised
|
|
|
Revised
|
|
|
Revised
|
|
|
|
|
|
|
|
March
|
|
|
June
|
|
|
September
|
|
|
December
|
|
|
Operating Revenues
|
|
$
|
707,056
|
|
|
$
|
821,919
|
|
|
$
|
1,081,967
|
|
|
$
|
745,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
(5)
|
|
$
|
59,577
|
|
|
$
|
90,683
|
|
|
$
|
283,793
|
(1)
|
|
$
|
54,744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operation
(5)
|
|
$
|
2,217
|
|
|
$
|
29,202
|
|
|
$
|
222,246
|
|
|
$
|
26,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to common stock
|
|
$
|
1,242
|
|
|
$
|
27,836
|
|
|
$
|
222,246
|
|
|
$
|
26,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share-Basic and diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From continuing operations
|
|
$
|
0.01
|
|
|
$
|
0.15
|
|
|
$
|
1.05
|
|
|
$
|
0.12
|
|
|
Net income applicable to common stock
|
|
$
|
0.01
|
|
|
$
|
0.14
|
|
|
$
|
1.05
|
|
|
$
|
0.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 Quarter Ended
|
|
|
|
|
Revised
|
|
|
Revised
|
|
|
Revised
|
|
|
|
|
|
|
|
March
|
|
|
June
|
|
|
September
|
|
|
December
|
|
|
Operating Revenues
|
|
$
|
648,996
|
|
|
$
|
701,038
|
|
|
$
|
959,126
|
|
|
$
|
721,082
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
58,953
|
|
|
$
|
80,894
|
|
|
$
|
162,750
|
|
|
$
|
56,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
(6)
|
|
$
|
(8,511
|
)
|
|
$
|
10,026
|
|
|
$
|
61,993
|
(3)
|
|
$
|
22,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (loss) applicable to common stock
|
|
$
|
(9,486
|
)
|
|
$
|
9,051
|
|
|
$
|
61,018
|
|
|
$
|
21,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share-Basic and diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From continuing operations
|
|
$
|
(0.07
|
)
|
|
$
|
0.05
|
|
|
$
|
0.34
|
|
|
$
|
0.12
|
|
|
Net Income (loss) applicable to common stock
|
|
$
|
(0.08
|
)
|
|
$
|
0.05
|
|
|
$
|
0.33
|
|
|
$
|
0.11
|
|
|
|
|
|
|
(1)
|
|
In the third quarter of 2006, operating income includes the reinstatement of deferred
energy of approximately $180 million.
|
|
|
|
(2)
|
|
In the fourth quarter of 2006, income from continuing operations includes a gain of
$62.9 million due to the sale of TGPC’s partnership interest in TGTC.
|
|
|
|
(3)
|
|
In the third quarter of 2005, income from continuing operations includes a charge of
$54 million for the inducement for debt conversion.
|
|
|
|
(4)
|
|
In the fourth quarter of 2005, income from continuing operations includes the reversal
of $20.9 million in interest charges as a result of settlements with terminated suppliers.
|
|
|
|
(5)
|
|
Operating Income and Income from Continuing Operations differs from amounts previously
reported in the March 31, June 30, and September 30, 2006 10Q’s by a reduction of ($9),
($48), and ($15), respectively, due to SPCOM being classified as assets held for use
rather than as discontinued operation. See Note 18 Discontinued Operations and Disposal
and Impairment of Long-Lived Assets.
|
176
|
|
|
|
|
(6)
|
|
Operating Income and Income from Continuing Operations differs from amounts previously
reported in the March 31, June 30 and September 2005 10Q’s by $5, $1 and ($134),
respectively, due to SPCOM being classified as assets held for use rather than as
discontinued operations. See Note 18 Discontinued Operations and Disposal and Impairment
of Long-lived Assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NEVADA POWER
|
|
|
|
|
2006 Quarter Ended
|
|
|
|
|
March
|
|
|
June
|
|
|
September
|
|
|
December
|
|
|
Operating Revenues
|
|
$
|
381,275
|
|
|
$
|
543,869
|
|
|
$
|
776,235
|
|
|
$
|
422,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
25,663
|
|
|
$
|
62,019
|
|
|
$
|
244,920
|
(1)
|
|
$
|
18,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
(3,296
|
)
|
|
$
|
28,456
|
|
|
$
|
211,113
|
|
|
$
|
(11,733
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 Quarter Ended
|
|
|
|
|
March
|
|
|
June
|
|
|
September
|
|
|
December
|
|
|
Operating Revenues
|
|
$
|
354,134
|
|
|
$
|
451,384
|
|
|
$
|
675,181
|
|
|
$
|
402,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
23,265
|
|
|
$
|
54,031
|
|
|
$
|
126,173
|
|
|
$
|
25,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
(8,033
|
)
|
|
$
|
20,969
|
|
|
$
|
99,472
|
|
|
$
|
20,326
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In the third quarter of 2006, operating income includes the reinstatement of deferred
energy costs of approximately $180 million.
|
|
|
|
(2)
|
|
In the fourth quarter of 2005, income from continuing operations includes the reversal
of $17.7 million in interest charges as a result of settlements with terminated suppliers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SIERRA PACIFIC POWER
|
|
|
|
|
2006 Quarter Ended
|
|
|
|
|
March
|
|
|
June
|
|
|
September
|
|
|
December
|
|
|
Operating Revenues
|
|
$
|
325,497
|
|
|
$
|
277,319
|
|
|
$
|
305,445
|
|
|
$
|
321,969
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
29,991
|
|
|
$
|
24,803
|
|
|
$
|
36,543
|
|
|
$
|
28,680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
13,272
|
|
|
$
|
8,999
|
|
|
$
|
20,028
|
|
|
$
|
15,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (deficit) applicable to common stock
|
|
$
|
12,297
|
|
|
$
|
7,633
|
|
|
$
|
20,028
|
|
|
$
|
15,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 Quarter Ended
|
|
|
|
|
March
|
|
|
June
|
|
|
September
|
|
|
December
|
|
|
Operating Revenues
|
|
$
|
294,548
|
|
|
$
|
249,335
|
|
|
$
|
283,683
|
|
|
$
|
318,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (loss)
|
|
$
|
29,519
|
|
|
$
|
21,710
|
|
|
$
|
38,139
|
|
|
$
|
26,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
12,137
|
|
|
$
|
4,899
|
|
|
$
|
21,858
|
|
|
$
|
13,180
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (deficit) applicable to common stock
|
|
$
|
11,162
|
|
|
$
|
3,924
|
|
|
$
|
20,883
|
|
|
$
|
12,205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In the fourth quarter of 2005, income includes the reversal of $3.2 million in interest
expense due to the settlement with Enron.
|
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
– Sierra Pacific Resources, Nevada Power
Company and Sierra Pacific Power Company’s principal executive officers and principal financial
officers, based on their evaluation of the registrants’ disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded
that, as of December 31, 2006, the registrants’ disclosure controls and procedures are adequate and
effective to ensure that material information relating to the
177
registrants’ and their consolidated
subsidiaries is recorded, processed, summarized and reported within the time period specified by
the SEC’s rules and forms, particularly during the period for which this annual report has been
prepared.
(b) Reports on Internal Control Over Financial Reporting
Management’s Report on Internal Control Over Financial Reporting
The management of Sierra Pacific Resources is responsible for establishing and maintaining
adequate internal control over financial reporting. Sierra Pacific Resources’ internal control
system was designed to provide reasonable assurance to the company’s management and board of
directors regarding the preparation and fair presentation of published financial statements.
Although Sierra Pacific Resources is firmly committed to effective internal controls over
financial reporting, internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can provide only reasonable
assurance with respect to financial statement preparation and presentation.
Sierra Pacific Resources’ management assessed the effectiveness of the Company’s internal
control over financial reporting as of December 31, 2006. In making this assessment, Sierra
Pacific Resources used the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in
Internal Control-Integrated Framework
. Based on our assessment we
believe that, as of December 31, 2006, the Company’s internal control over financial reporting is
effective based on those criteria.
Sierra Pacific Resources’ independent registered public accountants have issued an audit
report on our assessment of the Company’s internal control over financial reporting.
March 1, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders of Sierra Pacific Resources
Reno, Nevada
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over
Financial Reporting, that Sierra Pacific Resources and subsidiaries (the “Company”) maintained effective internal control over
financial reporting as of December 31, 2006, based on criteria
established in
Internal Control-Integrated Framework
issued by
the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of
the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control
over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control
over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of
internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s
principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board
of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A
company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only
in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material
effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting including the possibility of collusion or improper
management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.
Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject
to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of
December 31, 2006, is fairly stated, in all material respects, based
on criteria established in
Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on
the criteria established in
Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2006 of the
Company and our report dated March 1, 2007 expressed an unqualified opinion on those financial statements and financial
statement schedules and included an explanatory paragraph regarding the Company’s adoption of Statement of Financial
Accounting Standards No. 123(R) and Statement of Financial Accounting Standards
No. 158.
DELOITTE
& TOUCHE, LLP
Reno, Nevada
March 1, 2007
(c) Changes in Internal Controls
None.
ITEM 9B. OTHER INFORMATION
None.
178
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
(a) Directors
The following is a listing of all the current directors of Sierra Pacific Resources (SPR),
Nevada Power Company (NPC), and Sierra Pacific Power Company (SPPC), and their ages. There are no
family relationships among them. Directors serve staggered three-year terms with three (or four)
terms of office expiring at each Annual Meeting, or until their successors have been elected and
qualified.
Directors whose terms expire in 2007:
James R. Donnelley, 71
Partner, Stet and Query, Ltd., a family-owned investment company, since June 2000. He retired
from R.R. Donnelley & Sons Company in June 2000, where he served as Vice Chairman of the Board from
July 1990 to June 2000 and as a Director from 1976 to May 2005. He is also a Director of PMP
Limited. Mr. Donnelley has served as a
Director of SPR since 1987, of SPPC since 1992, and was elected a Director of NPC in July 1999.
Walter M. Higgins, 62
Chairman and Chief Executive Officer of SPR and Director and Chief Executive Officer of NPC
and SPPC since August 2000. Mr. Higgins served as Chairman,
President and Chief Executive Officer of AGL Resources, Inc., from
February 1998 to August 2000. He is also a director of AEGIS Insurance Services, Inc., Edison
Electric Institute, American Gas Institute, Desert Research Institute
Foundation Board, and several not-for-profit organizations. He is a trustee of Sierra Nevada College.
Brian J. Kennedy, 63
Mr. Kennedy
is President and Chief Executive Officer of Argonaut, LLC. He is also Chairman
of Meridian Gold, Inc., having retired as President and CEO in 2006.
Prior to that, he served approximately nine years as President and
Chief Operating Officer of FMC Gold Company. He is also a Director of
two non-profit corporations: the Nevada Museum of Art and the
Community Foundation of Western Nevada. Mr. Kennedy was elected
as a Director of SPR, SPPC and NPC in February 2007.
John F. O’Reilly, 61
Chairman and Chief Executive Officer of the law firm of O’Reilly Law Group LLC and John F.
O’Reilly, APC., Chairman and an Officer and/or a Board member of various family-owned business
entities and related investments and businesses. He serves as a Director of the Community Board of
Wells Fargo Bank Nevada, N.A., Director of Herbst Gaming, Inc., UNLV Foundation, Nevada Development
Authority, Advisory Board of Boys and Girls Clubs of Las Vegas, a member of the Las Vegas Chamber
of Commerce Government Affairs Committee, and is involved in various other capacities in other
not-for-profit organizations, including Vision 2020, on which he serves as Chairman/CEO and Board
member. Mr. O’Reilly has been a Director of NPC since 1995,
and was elected a Director of SPR and SPPC in July 1999.
Michael W. Yackira, 55
President and Chief Operating Officer of SPR, and Director of SPR since February 2007. Mr.
Yackira was previously Corporate Executive Vice President and Chief Financial Officer from October
2004 to February 15, 2007. From December 2003 to October 2004 he held the position of Executive
Vice President and CFO, at both NPC and SPPC. Mr. Yackira was previously Executive Vice President,
Strategy and Policy, from January to December 2003. Previously he was the Vice President and CFO of
Mars, Inc. from 2001 to 2002. Prior to that, Mr. Yackira was with
Florida based FPL Group, Inc., from 1989 to 2000. Mr. Yackira is a board member of the
United Way of Southern Nevada, the American Heart Association of
Las Vegas, and several not-for-profit organizations.
Directors whose terms expire in 2008:
Joseph B. Anderson, Jr., 64
Chairman and CEO of TAG Holdings, LLC. Mr. Anderson is on the Board of Rite Aid Corporation,
Quaker Chemical Corporation, ArvinMeritor, Inc., MDL Capital Management and Valassis Communications, Inc. He is Director of the
Original Equipment Suppliers Association, a member of the Michigan Automotive Partnership, Director of the Society of Automotive Engineers
Foundation and Director, Society of Automotive Engineers
International, Executive of the Committee of the National Association of Black Automotive Suppliers, and Board of Governors of the Center for Creative Leadership.
Mr. Anderson was elected as a Director of SPR, SPPC and NPC in February 2005.
179
Krestine M. Corbin, 69
President and Chief Executive Officer of Sierra Machinery, Incorporated, a machine tool
manufacturing company, since 1984 and a director of that company since 1980. Ms. Corbin has served
as a Director of SPR since 1989, of SPPC since 1992, and was elected a Director of NPC in July
1999.
Philip G. Satre, 57
Mr. Satre retired January 1, 2005, as Chairman of the Board, Harrah’s Entertainment, Inc., a
gaming entertainment company. Previously he was CEO of Harrah’s Entertainment from 1993 to 2003. He
is a Director of TABCORP
Holdings Limited (Australia), Nordstrom Inc., and Rite Aid
Corporation, as well as the National Center for Responsible Gaming
and the Nevada Cancer Institute. He is a Trustee of Stanford
University, the World War II Museum, Inc. and the UC Davis School of Law Alumni Association
Board. Mr. Satre was elected as a Director of SPR, SPPC, and NPC in January 2005.
Clyde T. Turner, 69
Owner
and Manager of Turner Investments Ltd., a general-purpose investment
company, co-owner of Global Trust
Ventures, LLC, a private equity fund and co-owner of Global Trust
Ventures Management, LLC. He
was elected a Director of SPR, NPC, and SPPC in November 2001.
Directors whose terms expire in 2009:
Mary Lee Coleman, 70
President of Coleman Enterprises, a developer of shopping centers and industrial parks. She is
also a director of First Dental Health, Inc. Ms. Coleman has served as a Director of NPC since
1980, and was elected a Director of SPR and SPPC in July 1999.
Theodore J. Day, 57
Chairman of Dacole Company, an investment firm. Formerly Senior Partner of Hale, Day,
Gallagher Company, a real estate brokerage and investment firm. He is also a
Director of the W.M. Keck Foundation, the Boy Scouts of America, Nevada Area Council, the Reno Air
Race Association, Linfield College, Western Exploration and Development, Ltd., and the National
Cowboy and Western Heritage Museum. Mr. Day has served as a Director of
SPPC since 1986, of SPR since 1987, and was elected a Director of NPC in July 1999.
Jerry E. Herbst, 69
Chief Executive Officer of Terrible Herbst, Inc., a gaming, resort and gasoline retail
company, since 1968. Mr. Herbst has served as a Director of NPC since 1990, and was elected a
Director of SPR and SPPC in July 1999.
Donald D. Snyder, 59
Mr. Snyder retired in March 2005 as President and Board Member of Boyd Gaming Corporation,
a gaming entertainment company. He is Director of Western Alliance
Bancorporation and Cash Systems, Inc. He is Chairman of the Las Vegas
Performing Arts Center Foundation. He is also Director of two non-public companies, Bank of Nevada and Switch
Communications Group, LLC. He serves on numerous not-for-profit organizations, including
Nathan Adelson Hospice, Nevada Development Authority, University of Nevada-Las Vegas
Foundation and Council for a Better Nevada. Mr. Snyder was elected a Director of SPR, NPC
and SPPC in November 2005.
Messrs. Day and Higgins are Directors of Tuscarora Gas Pipeline Company; Mr. Higgins is a
Director of Lands of Sierra, Inc., Great Basin Energy Company, Sierra Pacific Energy Company,
Sierra Pacific Communications, Sierra Water Development Company, Sierra Gas Holdings Company, Piñon
Pine Co. LLC, SPPC Funding LLC, and Nevada Electric Investment Co. All of the above-listed
companies are subsidiaries of Sierra Pacific Resources, with the exception of Piñon Pine Co. LLC,
and SPPC Funding LLC which are subsidiaries of Sierra Pacific Power Company and Nevada Electric
Investment Co. which is a subsidiary of Nevada Power Company.
(b) Executive Officers
See Executive Officers of the Registrant immediately following Item 4
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, or the Exchange Act, requires that
Directors, officers, and any holders of more than 10% of SPR’s common stock file reports with the
SEC disclosing ownership of the SPR’s stock and changes in beneficial
180
ownership. Officers, Directors and 10% stockholders are required by SEC regulations to
furnish SPR with copies of all Section 16(a) forms they file.
To SPR’s knowledge, based solely on review of its records and written representations by
persons required to file these reports, during 2006, all filing requirements under Section 16(a)
were complied with in a timely fashion.
Audit Committee
The Audit Committee consists of the following individuals: Philip Satre, Krestine M. Corbin,
Donald Snyder and Clyde T. Turner, who are all independent as defined in the listing standards
under the New York Stock Exchange (NYSE) rules. The Board of Directors of SPR, NPC and SPPC have
determined that Audit Committee member Clyde T. Turner is an “audit committee financial expert” as
defined by the SEC.
Code of Ethics
SPR, NPC and SPPC have adopted a code of ethics that applies to the Chief Executive Officer,
Chief Financial Officer and to the Controller. The code of ethics is set forth on our website at
sierrapacificresources.com.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
Compensation Overview
The Compensation Committee, or the Committee, of SPR, is composed entirely of directors who
are independent in accordance with NYSE rules. The purpose of the Committee is to evaluate the
compensation of the officers of SPR (and their performance relative to their compensation) and
assure that they are compensated effectively in a manner consistent with the stated compensation
strategy of SPR, internal fairness considerations, competitive practice and the requirements of the
appropriate regulatory bodies. In addition, the Committee is responsible for reviewing and
assessing SPR’s policies, plans and levels of health, welfare and benefit plans, together with the
administration of such plans.
As the holding company of two growing utilities, SPR faces many business issues. During 2006,
these issues included: improving its debt profile, increasing its credit ratings, settling of
contractual and regulatory disputes, increasing internal generation capability, managing energy
portfolio risk, and maintaining regulatory relationships. The Committee has determined that it is
in the best interest of SPR’s shareholders and customers to attract and retain those individuals
with the appropriate ability, knowledge and experience to help SPR deal effectively with these
issues. Accordingly, the Committee has established a compensation program, which it reviews at
least annually, for the principal executive officer, Walter M. Higgins, who served during 2006 as Chairman of
the Board, President and Chief Executive Officer (the “CEO”); the principal financial officer during 2006,
Michael W. Yackira, who served as Corporate Executive Vice President and Chief Financial Officer; and the other
named executive officers, Paul J. Kaleta, Roberto R. Denis, and
Jeffrey Ceccarelli (collectively with Messrs. Higgins and Yackira, the NEOs). On February 15, 2007, the Board of Directors elected Mr. Higgins Chairman
of the Board and Chief Executive Officer, and elected Mr. Yackira President and Chief Operating Officer. The primary
objectives of SPR’s compensations program are to:
|
|
•
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Assess the performance of individuals against key organizational objectives and reward
performance that either meets or exceeds those objectives.
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•
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Ensure continuity of superior performance and retention of key executives.
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•
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Attract qualified candidates.
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To that end, the Committee has developed a mix of compensation, primarily consisting of cash,
equity, retirement plans, other benefits and perquisites, all of which are discussed in more detail
below under “Components of the Executive Compensation Program.” For 2006, the components of cash
compensation, equity compensation and retirement plans are as follows:
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o
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Salary
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o
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Short Term Incentive Plan (STIP)
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o
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Cash allowance
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•
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Equity Compensation—Long Term Incentive Plan (LTIP)
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o
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Non-Qualified Stock Options
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o
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Performance Shares
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o
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Pension Plan (Qualified Plan)
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o
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Non-Qualified Restoration Plan
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o
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Non-Qualified Supplemental Executive Retirement Plan (SERP)
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o
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Non Qualified Deferred Compensation Program
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181
The Committee has authority under its charter to retain the services of independent counsel,
accountants or other consultants it deems necessary or appropriate to assist it. In accordance
with this authority, the Committee engages Towers Perrin, as
independent, external compensation consultants. In addition, Towers
Perrin provides actuarial services and benefit consulting services to
SPR. As requested, representatives of Towers
Perrin attended Committee meetings in 2006. Towers Perrin apprises the Committee annually on
current compensation practices, including how much compensation other companies deliver in cash
versus equity, weighting of short term versus long term awards, market evaluations of base salary,
short and long term incentive plans, perquisites and post retirement benefits, legal and disclosure
issues related to compensation, valuation models for equity grants and other compensation matters.
The peer group that SPR is compared to consists of other utility and energy services companies that are similar to SPR in terms
of the number of full time employees and revenues. SPR considers other energy and utility firms with revenues between $3 billion and three thousand employees as similar for comparison purposes.
Compensation Philosophy
General
The Committee believes that compensation should seek to encourage performance by the NEOs
that is aligned with the key objectives of SPR on both a short-term and long-term basis and should
help SPR in attracting and retaining qualified executives. The Committee does not have
prescriptive policies for how NEOs are to be compensated beyond the minimum guidelines that are
spelled out in the CEO’s employment contract and in the employment offer letters for the remaining
NEOs. The Committee believes its compensation programs for NEOs are realistic, contemporary and
in keeping with best practices within the industry.
The Committee makes compensation decisions for NEOs based upon business conditions, corporate
goals and conditions that exist in the unique regulatory climate of an investor-owned utility. The
mix and type of short-term and long-term awards for any given year are reviewed annually with the
CEO, the Chief Administrative Officer, Stephen R. Wood, and Towers Perrin prior to the February
Board meeting. Recommendations to the Committee for the total compensation for the NEOs, other
than the CEO, are made by the CEO, with advice from the external consultants. None of the NEOs
participates in the determination of their own compensation plans. The CEO is not present and is
not involved in the discussions of total compensation recommendations for himself.
The Committee believes that the interests of SPR’s shareholders and customers are best served
when SPR can attract and retain executives with compensation packages that are market competitive
and yet fair and prudent within the environment of an investor-owned regulated utility. The
Committee seeks to pay total direct compensation around the 50th percentile of other companies in
its peer group, as discussed above. Total direct compensation is equal to the sum of cash
compensation and the expected value of long-term incentives.
Incentive Compensation
The Committee annually provides short-term and long-term incentive compensation under two
plans, the STIP and the LTIP, which provide for cash and stock compensation based on conditions set
by the Committee. The STIP portion of compensation forms the variable cash component of annual
compensation and is based on some combination of company-wide financial performance goals, customer
satisfaction and operational performance and individual performance. The LTIP portion of
compensation provides for equity grants and is typically tied to more long range goals. LTIP
grants can be made in the form of performance shares or units, SAR’s, restricted shares, bonus
stock, non-qualified or incentive stock options and/or cash.
The primary purpose of grants under the STIP and the LTIP is to achieve a focused, concerted
effort on specific aspects of both company and individual performance. In addition, the Committee
believes that grants under the STIP and the LTIP are useful in helping to retain key executives who
are achieving superior performance against SPR goals by motivating them to remain in their
positions and in encouraging continued performance excellence. The Committee attempts to provide
substantially more potential value to the NEOs through the LTIP rather than the STIP. This
greater potential value is intended to increase the retention element of the executive compensation
program.
In determining the grants to be made under these plans, the Committee considers the following
factors:
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o
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the incentive compensation set and paid in recent years;
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o
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the desire to ensure that a substantial portion of total compensation is based upon performance;
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o
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the relative importance of the corporate, business unit and individual goals in any given year; and
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o
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competitive information, analyses and recommendations provided by Towers Perrin.
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182
To the extent that performance goals are attached to grants under the STIP and LTIP, full
achievement of those goals is often difficult. The Committee does not believe, however, that it is
prudent to establish reward thresholds that are highly unlikely to be attained under any scenario.
The size and content of awards under the STIP and the LTIP vary from year to year. In the
recent past, when SPR was facing challenges as a result of the western energy crisis and legal
disputes with Enron, the Committee’s compensation decisions were focused more on the challenges of
retaining NEOs. Time-vested restricted stock for the CEO and NEOs, and in the case of the CEO, a
retention bonus were used at that time to reflect this goal. As SPR has rebounded from those
difficulties and its stock price has improved, the Committee has chosen to put more emphasis on
stock performance and the attainment of specific corporate goals in the LTIP award program.
Accordingly, two-thirds of the LTIP awards for each NEO, other than the CEO, in 2006 was based
on SPR’s total shareholder return against the performance of other utilities, as described in more
detail below. The remaining one-third of the 2006 LTIP grant to each of the NEO’s was in the form
of non-qualified stock options. These grants reflect the Committee’s desire to continue to focus
on share price growth and the related increase in shareholder value. In the case of the CEO, all
of his LTIP grants were in the form of performance shares linked to specific performance
milestones.
The Committee has followed a practice of making all STIP and LTIP grants to its executive
officers on a single date each year, normally at its regularly scheduled Committee meeting in
February. All option awards made to NEOs or any of the other employees are made pursuant to SPR’s
LTIP plan. All options under the LTIP are granted with an exercise price equal to the fair market
value of SPR’s common stock on the date of the grant. Fair market value is defined under the LTIP
to be the closing market price of a share of common stock on the date of the grant. All equity
grants to NEOs are made by the Committee. While SPR does not have any program or practice to time
option grants to executive officers in coordination with the release of material non-public
information, it does not time the release of such information for the purpose of affecting the
value of executive compensation. The Committee does not have any program, plan or practice of
awarding options and setting the exercise price of option grants by using average prices (or lowest
prices) of common stock in a period preceding, surrounding or following the grant date.
Tax Deductibility of Pay
Section 162(m) of the Internal Revenue Code of 1986, as amended, limits the amount of
compensation that SPR may deduct in any one year to $1,000,000 with respect to each of its five
most highly compensated executive officers. There is an exception to that limitation for certain
performance-based compensation. For 2006, management believes that
substantially all of the compensation paid to its executive officers
satisfies the requirements for deductability under Section 162(m).
Minimum Ownership Guidelines
The Committee has established minimum ownership guidelines for NEOs. The CEO is expected to
maintain two times his annual salary in SPR stock, and the remaining NEOs are expected to maintain
one and a half times their annual salary in SPR stock. The CEO and the NEOs have five years from
the date of their employment to meet this requirement.
Other Benefits
The Committee attempts to provide retirement benefits, perquisites and post termination
commitments to NEOs that are consistent with those generally offered by other utilities, based in
part on the Committee’s review of annual market assessments performed by Towers Perrin.
Components of the Executive Compensation Program
This section outlines the components of SPR’s compensation program for NEOs and explains why
the Committee believes that each is important and how it relates to SPR’s overall strategy on
compensation.
Cash Compensation
Cash compensation for NEO’s in 2006, which consisted primarily of base salary and incentives
under the STIP, was designed to deliver cash compensation at approximately the 50th percentile of
the market rate for similar positions within the selected peer group companies, discussed above.
Performance-based STIP incentives are designed to motivate NEOs to pursue specific short term
objectives that are consistent with the immediate needs of the business in the year of grant.
Salary
The base salary for each NEO is set by the Committee at its meeting in February each year.
The CEO has an employment agreement that provides a minimum base salary. The other NEOs have
minimum salaries established by their offer letters. Increases
183
or decreases to base salary for the
CEO are made by the Committee. In making this determination, the Committee reviews the performance
of the CEO and reviews market information provided by Towers Perrin.
For the NEOs, other than the
CEO, annual compensation recommendations are made to the Committee by the CEO, based upon his
review of their respective performances and market information provided by Towers Perrin. The
Committee has final approval authority for salaries for the NEOs. In
establishing salaries, the Committee is mindful of its overall goal to pay cash compensation to its
executive officers at approximately the 50th percentile of cash compensation paid by other peer
group companies, as discussed above.
The amount of cash compensation that is provided in the form of base salary is generally less
than the potential amount that is provided in the form of bonuses under SPR’s combined STIP and
LTIP plans, assuming threshold performance levels are met. This weighting reflects the Committee’s
objective to ensure that a substantial amount of each NEO’s total compensation is tied to the
achievement of short term and long term corporate, business unit and individual performance goals.
Short Term Incentive Plan (STIP)
The STIP provides for cash payments to all employees based upon the achievement of goals set
for a single fiscal year. The plan is reviewed and revised annually by the Committee and metrics
are developed for overall corporate goals as well as goals for each business unit within SPR.
Goals and metrics for STIP are laid out in a “scorecard,” which is measured and monitored by the
Finance and Internal Audit groups within SPR. Overall corporate goals and individual departments
progress against the scorecard is available to employees in hard copy and electronic form on a
quarterly basis.
The STIP plan allows the CEO to consider the overall financial performance and the condition
of SPR in finally determining whether or not to make or reduce the STIP payment. However, the CEO
has utilized his authority to pay or withhold STIP payments when the performance criteria has or
has not been met, only under exceptional circumstances. The CEO’s discretion to make or withhold
payments that would otherwise be made or not be made is applied on a company wide basis, not a
case-by-case basis.
At the February Committee meeting, the Committee sets target STIP goals for each of the NEOs
based upon input and discussions with management and the external compensation consultants.
Target STIP bonuses in 2006 were set at 75% of base salary for the CEO and set at 50% of base salary for the
other NEOs. For 2006, the Committee selected categories upon which to
gauge SPR’s and NEOs’ annual performance. Each category was
assigned a percentage weighting as follows:
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Financial Performance
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30
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%
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Customer Perception
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30
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%
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Business Unit Performance
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20
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%
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Individual Performance Assessment
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20
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%
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Financial Performance is measured by the amount of expenditures relating to operations,
maintenance and capital spending versus approved financial budgets, as well as the management of
employee headcounts. Since the control of expenditures for operations and maintenance is
critical, these expenditures were assigned a 50% weighting in the STIP calculation. The
calculation measures actual expenditures compared to budgeted expenditures, and tracks this data
from the Monthly Executive Financial Summary report with data from the General Ledger. Control
of Capital spending was assigned a 40% weighting in the STIP calculation, and it also measures
actual expenditures compared to budgeted expenditures. This data was also tracked in the Monthly
Executive Financial Summary report with data from the General Ledger. Control of employee
headcount was considered to be important in managing Company costs. This measure was assigned a 10% weighting in the STIP
calculation. Data from this measure is derived from the Human Resource database.
As SPR continues to expand and grow, SPR believes that it is important to maintain and improve
customer perception of service levels. Customer perception is measured by the firm of Market
Strategies, Inc. They select a statistically significant sample of residential, commercial and
major account customers who are asked to rate what they feel about SPR on a scale of zero to ten,
with zero being very unfavorable and ten being very favorable. A weighting of 100% is assigned to
this measure of customer satisfaction for STIP purposes.
Specific Business Unit Performance measures are developed for each of SPR’s six organizational
units, as well as SPR’s two local unions. Each organizational unit and union typically has at
least five measures that are important to the success of the overall company.
Individual performance is also a component of compensation for the CEO and NEOs
under the STIP program and it is assigned a weighting of 20%. Annually, the
performance of the CEO is evaluated by the Committee, and the Chair of the Committee
has the authority to determine a payment to the CEO under the individual performance
component of the STIP program. The Chair of the Committee and the CEO make the
determination on payments to the NEOs regarding the individual performance
component of the STIP program.
As mentioned, the CEO has the discretion to determine whether SPR’s performance merits a
recommendation to the Committee as to whether or not to make STIP payments. Actual payments under
STIP can range for each NEO from nothing to 150% of the NEO’s target percentage. For fiscal 2006,
SPR exceeded all minimum thresholds for STIP goals, which generated award payments under the STIP
for the CEO of 80% of his base salary, and for each NEO, of approximately 50% of his base salary.
184
Cash Allowance
The
CEO and each NEO is given a cash allowance, which can be used at
their discretion. Typically, this group has used their cash allowance
to offset expenses associated with acquiring financial planning and
tax services, or to purchase / lease a vehicle to be used for
business purposes. The Board of Directors elected to use cash allowances
to simplify the administrative process of handling such requirements. For 2006, the CEO’s cash
allowance was $30,000 and the remaining NEOs received between $11,000 and $15,000 each.
Equity Compensation
Long Term Incentive Plan (LTIP)
In
2006, the NEOs, other than the CEO, received two-thirds of the value of their LTIP awards in the form of
Performance Shares and the other third in non-qualified stock
options, or NQSO’s; all of the CEO’s LTIP awards were in the
form of performance shares. The Committee
believes that the 2006 equity awards serve to align the interests of
the NEOs, with SPR’s
shareholders and customers as they were weighted more heavily for performance against the Dow Jones
Utility average than simple share price appreciation. While share price is a key indicator of the
success of any public enterprise, the Committee believes that outperforming the peer group of
companies in the DJUI is more critical to the success of SPR during the period over which the 2006
LTIP grants will vest.
The amount of equity compensation that is provided to each NEO in a given year is generally
determined in reference to the NEO’s base salary for that year. The Committee generally approves
an award for each NEO each year with a present cash value that is determined by multiplying the
NEO’s base salary by a percentage. The percentage that the Committee selects for a given year
depends upon the Committee’s assessment of the appropriate balance between cash and equity
compensation. In making that assessment, the Committee considers factors such as the relative
merits of cash and equity as a device for retaining and motivating NEOs and practices used by
other utility and energy companies. In 2006, the Committee resolved to make equity awards that had
a present cash value equal to 86% of base salary compensation to the
NEOs, with the exception of
the CEO. The present cash value of LTIP NQSO’s was determined by using a modified binomial
valuation model calculated by the external compensation consultant, Towers Perrin, and assumptions
regarding turnover, dividend trends and the expected life of the options. The CEO has a
performance contract which calls for his long-term incentive performance to be measured and
rewarded quarterly. On a quarterly basis, the CEO is measured on the following criteria:
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•
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total shareholder return against the Dow Jones Utility Index;
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•
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recovery of deferred energy disallowed in NPC’s 2001 Deferred Energy Case;
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•
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restoration of investment grade status for the Utilities’ senior secured debt;
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•
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a satisfactory achievement of regulatory and litigation milestones as measured by the Board;
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•
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restoration of the common stock dividend; and
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•
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attaining Public Utilities Commission of Nevada approval and securing all necessary
licenses and permits required to commence construction of the Ely Energy Center.
|
While most of SPR’s stock option awards to NEOs have historically been made pursuant to its
annual grant program under the LTIP, the Committee retains the discretion to make additional awards
to executive officers at other times, in connection with the initial hiring of a new officer, for
retention purposes or otherwise. In 2006, the Committee granted such awards to a newly hired
executive with a grant price equal to the closing price of SPR’s common stock on the day he signed
his employment agreement. SPR does not have any program, plan or test practice to time such
additional awards in coordination with the release of material non-public information.
In 2006, the Committee reduced the CEO long-term incentive award during a quarterly
measurement period, based upon their assessment of his performance against specific SPR objectives
specified in his employment agreement. Under the terms of the
CEO’s employment agreement, in connection with regulatory and
litigation measures, the Board may use discretion as to the number of shares delivered based on their
assessment of the level of achievement. The Committee believed that a
partial award was justified in connection with these
milestones for settlement of the Enron litigation.
Non-Qualified Stock Options
Non-Qualified Stock Options granted under the LTIP may vest on the basis of the satisfaction
of performance conditions established by the Committee or on the basis of a passage of time and
continued employment. The NQSO’s granted in 2006 are time vested, one-third per year over the
three-year period from the date of the grant. The NQSO’s have a ten year option life, and contain
forfeiture provisions in the case of certain terminations of employment.
185
Performance Shares
Performance Shares are shares that typically vest at the end of a three-year period to the
extent that specific performance targets determined by the Committee are met. If these objectives
are not met, the Performance Shares are forfeited. Performance Shares do not have any voting
rights in stockholder votes. Performance shares may be paid in stock or cash equivalents after
vesting and do not entitle the recipient to receive dividends or dividend equivalents.
In 2006, Performance Shares granted under the LTIP were based on SPR’s Total Shareholder
Return (TSR) compared to the TSR of Dow Jones Utility Index companies. The CEO did not participate
in this grant since he was provided with the employment agreement LTIP opportunity discussed above.
The Performance Shares for the remaining NEO’s are measured at the end of a three year calendar
period against the Dow Jones Utility Index. Shares will be earned according to the table shown
below:
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Performance
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Shares
Earned
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Below 35th Percentile
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0% of grant
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35th Percentile
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50% of grant
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50th Percentile
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100% of grant
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75th Percentile
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150% of grant
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Retirement Plans
Pension Plan (Qualified Plan)
SPR has a tax-qualified, noncontributory defined-benefit pension plan that covers certain
eligible employees, including the NEOs. Benefits under the Pension Plan are based upon the
employee’s years of service and his or her highest average
earnings for a five consecutive calendar year period with SPR and its subsidiaries. Benefits are
payable after retirement in the form of an annuity; lump sum payments are only available to
terminated employees who have less than a $50,000 actuarial present value. Earnings, for purposes of the
calculation of benefits under the Pension Plan, are generally defined to include base salary and
STIP payments and exclude other forms of compensation. The amount of annual earnings that may be
considered in calculating benefits under the Pension Plan is limited by law. For 2006, the annual
limitation was $220,000.
Benefits under SPR’s Pension Plan are calculated as an annuity according to the following
formula:
(1.325%
x “Final Average Earnings” x “Benefit Accrual Service”) + (0.475% x “Excess Compensation” [over the
Social Security covered compensation] x “Benefit Accrual Service” up to 35 year maximum)
Contributions to the Pension Plan are made exclusively by SPR and are paid into a trust fund
from which benefits are paid to participants. The Pension Plan currently limits pensions paid
under the plan to an annual maximum of $175,000 payable beginning at age 65 in accordance with IRS
requirements.
Non-Qualified Restoration Plan
SPR also has an unfunded pension plan (the Non-Qualified Restoration Plan) that provides for
payments out of the general assets of SPR an amount substantially equal to the difference between
the amount that would have been payable under the Qualified Plan, in the absence of laws limiting
pension benefits and earnings that must be considered in calculating pension benefits, and the
amount actually payable under the Qualified Plan. The formula for determining this benefit is the
same as for the Qualified Plan. In the Non-Qualified Restoration Plan, total compensation (as
defined in the Qualified plan) is used and the Qualified Plan portion of the payment is subtracted,
leaving a benefit payment from the Non-Qualified Restoration Plan to be net of Qualified Plan
payment.
Non-Qualified Supplemental Executive Retirement Plan or SERP
The SERP was adopted by SPR in 1990 and restated in May of 2002. The plan provides for
payments beginning at age 65 of an annual amount determined by the following formula:
Step 1
. (3.0% x SERP “Final Average Earnings*” x “Years of Service” up to 15 years) + (1.5%
x SERP Final Average Earnings” x “Years of Service” over 15 yrs).
Step 2.
Less the benefit payable under the Qualified Retirement Plan.
(1.325% x “Final Average Earnings” x “Benefit Accrual Service”) + (0.475% x “Excess
Compensation” x “Benefit Accrual Service” up to 35 year maximum)
186
Step 3.
Less the benefit payable under the Non Qualified Restoration Plan (already included
in Step 2, if IRS limitation rules are not taken into account).
*SERP “Final Average Earnings” reflect a three consecutive calendar year period, but otherwise are only minimally different than “Final Average Earnings”
under the Qualified Pension Plan and include specific income items approved by the Board of
Directors.
The CEO and the NEOs participate in the SERP. The SERP is designed to provide a competitive
supplemental benefit that is beneficial in the attraction and retention of key executive talent.
Non-Qualified Deferred Compensation Program
Executive officers are also eligible for participation in the Non-Qualified Deferred
Compensation program, which is a supplement to the 401(k) program. All employees are eligible for
participation in the NQDC plan if they make in excess of $110,000 in base salary and are in the top
5% highly compensated group of employees. The Plan provides eligible participants the opportunity
to defer compensation on a pre-tax basis and direct the investment of these amounts in hypothetical
investments that mirror the 401(k) investment options. The “match restoration” provision of the
Plan provides for an employer match, according to the 401(k) plan design, which is not otherwise
provided under SPR’s 401(k) Plan due to IRS defined limits.
This “match restoration” under the Plan when added to the employer match provided under SPR’s
401(k) Plan will result in a 100% match of employee contributions up to 6% of eligible earnings.
Other Benefits
General employee benefits for medical, dental and vision insurance, 401(k) plan, ESPP, and
life insurance and disability coverage are made available to all nonunion Management, Professional
and Technical (MPAT) employees at SPR. These same benefit offerings form part of the compensation
for the NEOs, and are identical to those offered to all other MPAT employees with two exceptions.
SPR provides the CEO with supplemental life insurance coverage per his employment contract of
$2,000,000 and life insurance while traveling with a death benefit of an additional $1,000,000.
All other NEOs are provided with supplemental life insurance coverage in the amount of $500,000.
Perquisites
SPR may provide NEOs with certain perquisites
.
These perquisites may include:
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•
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Housing Allowances (for alternate work locations)
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•
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Executive Physical Programs
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•
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|
Tax gross ups on specific expenses
|
A complete listing and value associated with these perquisites are shown in the Summary
Compensation table as “All Other Compensation.”
SPR provides these perquisites for different reasons that are of benefit to SPR. These
perquisites reflect competitive business practices for SPR’s competitive peer group, and the
Committee considers them necessary for retention and recruitment purposes. The Committee reviews
the perquisites provided to the NEOs on a regular basis in an attempt to ensure that they continue
to be appropriate in light of the Committee’s overall goal of designing a compensation program for
NEOs that maximizes the interests of the shareholders and customers.
Post -Termination Compensation
SPR has entered into change in control severance agreements with all of the NEOs. These
agreements provide for payments and other benefits if the officer’s employment terminates for a
qualifying event or circumstances, including, but not limited to, being terminated without “cause”
or leaving employment for “good reason” as these terms are defined in the severance agreements.
Additional information regarding the Severance Agreements and the Transitional Compensation
Agreements including a definition of key terms and a quantification of benefits that would have
been received by SPR’s NEOs had termination occurred on or before December 31, 2006 is found under
the heading “Potential Payments upon Termination or Change in Control” of the Compensation
Discussion and Analysis.
The Committee believes that these severance and transitional compensation arrangements are an
important part of overall compensation for the NEO’s. The Committee believes that these agreements
will help to secure the continued employment and focus of the NEOs, notwithstanding any concern
that they might have regarding their own continued employment, prior to or following a
187
change in
control. The Committee also believes that these agreements are an important recruiting and
retention tool, as most of the companies with which SPR competes for talent have similar agreements
in place for their senior executives.
SUMMARY COMPENSATION TABLE
The following table sets forth information about the compensation of the Chief Executive
Officer, the Chief Financial Officer and each of the three most highly compensated officers, for
services in all capacities to SPR and its subsidiaries.
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Change in
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Non-
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Qualified and
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Equity
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Non-Qualified
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All Other
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Stock Awards
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Option
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Incentive
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Deferred
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Compensation
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Name and Principal
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Bonus ($)
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($)
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Awards ($)
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Plan ($)
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|
Compensation
|
|
($)
|
|
|
|
|
|
Position
|
|
Year
|
|
Salary ($)
|
|
(1)
|
|
(2)
|
|
(2)
|
|
(3)
|
|
($)(6)
|
|
(7)
|
Total ($)
|
|
|
|
|
Walter M. Higgins (5)
|
|
|
2006
|
|
|
$
|
743,654
|
|
|
$
|
333,333
|
|
|
$
|
1,998,892
|
|
|
$
|
—
|
|
|
$
|
594,750
|
|
|
$
|
1,719,679
|
|
|
$
|
180,705
|
|
|
$
|
5,571,013
|
|
|
Chairman of the
Board,
President, and
Chief
Executive
Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael W. Yackira (5)
|
|
|
2006
|
|
|
$
|
373,846
|
|
|
$
|
—
|
|
|
$
|
260,466
|
|
|
$
|
376,527
|
|
|
$
|
200,000
|
|
|
$
|
196,991
|
|
|
$
|
57,577
|
|
|
$
|
1,465,408
|
|
|
Corporate Executive
Vice
President,
Chief Financial
Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paul J. Kaleta (4)
|
|
|
2006
|
|
|
$
|
268,846
|
|
|
$
|
65,000
|
|
|
$
|
174,601
|
|
|
$
|
221,505
|
|
|
$
|
150,000
|
|
|
$
|
41,554
|
|
|
$
|
341,498
|
|
|
$
|
1,263,004
|
|
|
Corporate Sr.
Vice
President, General
Counsel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Roberto R. Denis
|
|
|
2006
|
|
|
$
|
297,693
|
|
|
$
|
—
|
|
|
$
|
218,097
|
|
|
$
|
324,913
|
|
|
$
|
165,000
|
|
|
$
|
189,990
|
|
|
$
|
58,108
|
|
|
$
|
1,253,800
|
|
|
Corporate Sr.
Vice
President, Energy
Supply
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey L. Ceccarelli
|
|
|
2006
|
|
|
$
|
332,115
|
|
|
$
|
—
|
|
|
$
|
229,241
|
|
|
$
|
62,908
|
|
|
$
|
165,000
|
|
|
$
|
394,995
|
|
|
$
|
88,640
|
|
|
$
|
1,272,899
|
|
|
Corporate Sr.
Vice
President, Service
Delivery and
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In 2006, Mr. Higgins received a retention incentive payment in the amount of $333,333,
and Mr. Kaleta was paid a signing bonus in the amount of $65,000.
|
|
|
|
(2)
|
|
“Stock Awards” consists of the values for performance shares and restricted stock;
“Option Awards” consists of the values for non-qualified stock options. Assumptions used
to value these awards are consistent with contemporary practices for their accounting
treatment and recognized in accordance with SFAS No. 123R
“Share Based Payments” in 2006. Reference Note 12,
Stock Compensation Plans, of the Footnotes to the Consolidated
Financial Statements.
|
|
(3)
|
|
The amounts presented for Non-Equity Incentive Plan awards consist of payments under
the Short-Term Incentive Plan earned in 2006, and are calculated using base salary which
could differ from the amount reported in the “Salary” column.
|
|
|
|
(4)
|
|
Mr. Kaleta was appointed to the position of Corporate Senior Vice President and General
Counsel in February 2006.
|
|
|
|
(5)
|
|
Effective February 15, 2007, Mr. Higgins’ is Chairman and Chief Executive Officer of
SPR, and Mr. Yackira is President and Chief Operating Officer of SPR.
|
|
|
|
(6)
|
|
Deferred Compensation reflects the following factors that
result in an increase in value:
|
|
|
i.
|
|
Increase in final average pay resulting primarily from
increases in incentive compensation payments made in 2006
|
|
|
|
|
ii.
|
|
Increase in service (by 1 year) used to calculate the benefit
|
|
|
|
|
iii.
|
|
Decrease in period to time before commencement (by 1 year)
|
|
|
|
|
|
|
|
|
|
The increase in incentive compensation payments reflects the
achievement of targeted goals and the overall improved financial
health of the company. Final average pay for purposes of the
calculation of the amounts shown in this table includes 2006
compensation in the averaging period, replacing the 2001 compensation
for Restoration Plan purposes and 2003 compensation for SERP purposes
that would be used in the prior year calculations.
|
|
|
|
(7)
|
|
Amounts for All Other Compensation include the following for 2006:
|
188
ALL OTHER COMPENSATION TABLE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Walter M.
|
|
|
Michael
|
|
|
Paul J.
|
|
|
Roberto R.
|
|
|
Jeffrey L.
|
|
|
Description
|
|
Higgins
|
|
|
W. Yackira
|
|
|
Kaleta
|
|
|
Denis
|
|
|
Ceccarelli
|
|
|
|
|
SPR contributions to the 401k deferred compensation plan
|
|
$
|
13,200
|
|
|
$
|
13,200
|
|
|
$
|
9,154
|
|
|
$
|
13,200
|
|
|
$
|
13,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Imputed income on group term life insurance and premiums
paid for executive term life policies
|
|
$
|
14,666
|
|
|
$
|
4,281
|
|
|
$
|
1,840
|
|
|
$
|
3,600
|
|
|
$
|
2,464
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash in lieu of forgone vacation
|
|
$
|
47,308
|
|
|
$
|
25,096
|
|
|
$
|
14,331
|
|
|
$
|
29,308
|
|
|
$
|
15,977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash allowance to be used at the discretion of the executive
|
|
$
|
30,000
|
|
|
$
|
15,000
|
|
|
$
|
11,077
|
|
|
$
|
12,000
|
|
|
$
|
15,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Housing Allowance (for alternate work location)
|
|
$
|
75,531
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
42,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relocation Expense
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
261,084
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax gross up on relocation expenses
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44,012
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
180,705
|
|
|
$
|
57,577
|
|
|
$
|
341,498
|
|
|
$
|
58,108
|
|
|
$
|
88,641
|
|
GRANTS OF PLAN-BASED AWARDS
All grants of plan-based awards to the named executive officers of SPR in 2006 are presented
in the table below. The incentive plans under which these grants were made are fully described in
the Compensation Discussion and Analysis section.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise
|
|
Grant Date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All
|
|
All
|
|
or Base
|
|
Fair Value
|
|
|
|
|
|
|
|
Estimated Future Payouts Under
|
|
Estimated Future Payouts Under
|
|
Other
|
|
Other
|
|
Price of
|
|
of Stock or
|
|
|
|
|
|
|
|
Non-Equity Incentive Plan Awards
|
|
Equity Incentive Plan Awards
|
|
Stock
|
|
Option
|
|
Option
|
|
Option
|
|
|
|
|
|
|
|
Threshold
|
|
Target
|
|
Maximum
|
|
Threshold
|
|
Target
|
|
Maximum
|
|
Awards
|
|
Awards
|
|
Awards
|
|
Awards
|
|
Name
|
|
Grant Date
|
|
|
|
($)
|
|
($)
|
|
($)
|
|
(#)
|
|
(#)
|
|
(#)
|
|
(#)
|
|
(#)
|
|
($/sh)
|
|
($)
|
|
|
|
Walter M. Higgins
Performance Shares
|
|
08/04/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,500
|
|
|
|
450,000
|
|
|
|
500,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,225,000
|
|
|
Short-Term
Incentive Plan
|
|
01/01/2006
|
|
|
|
|
|
|
|
$
|
594,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael W. Yackira
Options
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,527
|
|
|
$
|
13.29
|
|
|
$
|
84,558
|
|
|
Performance Shares
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,432
|
|
|
|
20,864
|
|
|
|
31,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
96,879
|
|
|
Short-Term
Incentive Plan
|
|
01/01/2006
|
|
|
|
|
|
|
|
$
|
200,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paul J. Kaleta
Options
|
|
02/01/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,000
|
|
|
$
|
13.10
|
|
|
$
|
144,600
|
|
|
Options
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,224
|
|
|
$
|
13.29
|
|
|
$
|
39,675
|
|
|
Options
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,112
|
|
|
$
|
13.29
|
|
|
$
|
10,189
|
|
|
Options
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,405
|
|
|
$
|
13.29
|
|
|
$
|
69,496
|
|
|
Performance Shares
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,575
|
|
|
|
17,149
|
|
|
|
25,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
79,629
|
|
|
Restricted Shares
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,643
|
|
|
|
|
|
|
|
|
|
|
$
|
74,995
|
|
|
Short-Term
Incentive Plan
|
|
01/01/2006
|
|
|
|
|
|
|
|
$
|
150,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Roberto R. Denis
Options
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,445
|
|
|
$
|
13.29
|
|
|
$
|
64,864
|
|
|
Performance Shares
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,003
|
|
|
|
16,005
|
|
|
|
24,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
74,317
|
|
|
Short-Term
Incentive Plan
|
|
01/01/2006
|
|
|
|
|
|
|
|
$
|
165,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey L. Ceccarelli
Options
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,886
|
|
|
$
|
13.29
|
|
|
$
|
71,816
|
|
|
Performance Shares
|
|
02/07/2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,860
|
|
|
|
17,720
|
|
|
|
26,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
82,280
|
|
|
Short-Term
Incentive Plan
|
|
01/01/2006
|
|
|
|
|
|
|
|
$
|
165,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
189
|
1.
|
|
Mr. Higgins’ performance share grant of 500,000 shares, dated August 4, 2006, was awarded
per an employment agreement executed on that date. Of this amount, 65,000 shares were
earned and issued in October 2006. The value of these vested shares is reflected in the
“Summary Compensation Table,” and the remaining unvested portion is included in the
“Outstanding Equity Awards at Fiscal Year-End Table.” A total of 353,282 outstanding
performance shares from his previous employment agreement, signed in 2003, were cancelled
upon the execution of this new agreement. According to the terms of his new employment
agreement, Mr. Higgins is entitled to receive the following performance shares with the
achievement of certain criteria, if they are met by June 1, 2008:
|
|
|
i.
|
|
Shareholder return as measured by the Dow Jones Utility Index:
|
|
|
1.
|
|
if SPR is positioned in the 40
th
percentile, 42,500 shares will be awarded.
|
|
|
|
|
2.
|
|
if SPR is positioned at or above the 50
th
percentile, 85,000 shares will be awarded.
|
|
|
|
|
3.
|
|
if SPR is positioned at or above the 70
th
percentile, 135,000 shares will be awarded.
|
|
|
ii.
|
|
Recover all of the deferred energy charges previously denied in the
2002 PUCN deferred energy case, 50,000 shares, with final assessment of
achievement to be at the discretion of the Board of Directors.
|
|
|
|
|
iii.
|
|
Restore investment grade status for the senior secured debt of the
Utilities, 100,000 shares, no award if goal is not attained.
|
|
|
|
|
iv.
|
|
Satisfactory achievement of remaining regulatory and litigation
milestones, as measured by the Board of Directors, 65,000 shares, final award to
be at the discretion of the Board of Directors.
|
|
|
|
|
v.
|
|
Restore quarterly common stock dividend, 100,000 shares, no award
if goal is not attained.
|
|
|
|
|
vi.
|
|
Attain PUCN approval and secure all necessary licenses and permits
required to commence construction of the proposed Ely plant, 50,000 shares,
number of shares awarded to be at the discretion of the Board of Directors.
|
|
2.
|
|
The performance share grants dated February 7, 2006 have a three year performance and
vesting period ending on December 31, 2008.
|
|
|
i.
|
|
The threshold represents the minimum acceptable performance which, if attained,
results in payment of 50% of the target award.
|
|
|
|
|
Performance below the minimum acceptable level results in no award earned.
|
|
|
|
|
ii.
|
|
The target indicates a level of outstanding performance and which, if attained, results in payment of 100% of the target award.
|
|
|
|
|
iii.
|
|
The maximum represents a level indicative of exceptional performance which, if
attained, results in a payment of 150% of the target award.
|
|
3.
|
|
For the executives listed above all option grants dated February 7, 2006 will vest over
three years at one-third per year, except for the option to purchase 30,000 shares and 2,112 shares, as described in footnote(4) below, granted to Mr. Kaleta.
|
|
|
|
4.
|
|
In addition to the above grants, upon his hire Mr. Kaleta was also granted:
|
|
|
i.
|
|
an option award of 30,000 shares, with a one year vesting period beginning on the
grant date of February 1, 2006.
|
|
|
|
|
ii.
|
|
a restricted shares award of 5,643 shares, with a grant date of February 7,
2006, which was fully vested on December 31, 2006.
|
|
|
|
|
iii.
|
|
an option award of 2,112 shares which will vest only upon the restoration of the
quarterly common stock dividend before February 7, 2010.
|
190
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table provides information about all awards held by the named
executive officers
at December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPTION AWARDS
|
|
|
STOCK AWARDS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan
|
|
|
Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Awards:
|
|
|
Awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
|
|
|
Market or
|
|
|
|
|
|
|
|
|
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
Number
|
|
|
Market
|
|
|
of
|
|
|
Payout
|
|
|
|
|
|
|
|
|
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
|
|
of
|
|
|
Value of
|
|
|
Unearned
|
|
|
Value of
|
|
|
|
|
|
|
|
|
|
|
|
Plan
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Shares or
|
|
|
Shares,
|
|
|
Unearned
|
|
|
|
|
|
|
|
|
|
|
|
Awards:
|
|
|
|
|
|
|
|
|
|
|
or Units
|
|
|
Units of
|
|
|
Units or
|
|
|
Shares,
|
|
|
|
Number of
|
|
|
Number of
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
|
of Stock
|
|
|
Stock
|
|
|
Other
|
|
|
Units or
|
|
|
|
Securities
|
|
|
Securities
|
|
|
Securities
|
|
|
|
|
|
|
|
|
|
|
that
|
|
|
that Have
|
|
|
Rights
|
|
|
Other
|
|
|
|
Underlying
|
|
|
Underlying
|
|
|
Underlying
|
|
|
|
|
|
|
|
|
|
|
Have
|
|
|
Not
|
|
|
that Have
|
|
|
Rights that
|
|
|
|
Unexercised
|
|
|
Unexercised
|
|
|
Unexercised
|
|
|
Option
|
|
|
Option
|
|
|
Not
|
|
|
Vested
|
|
|
Not
|
|
|
Have Not
|
|
|
|
Options (#)
|
|
|
Options (#)
|
|
|
Unearned
|
|
|
Exercise
|
|
|
Expiration
|
|
|
Vested
|
|
|
($)
|
|
|
Vested
|
|
|
Vested ($)
|
|
Name
|
|
Exercisable
|
|
|
Unexercisable
|
|
|
Options (#)
|
|
|
Price ($)
|
|
|
Date
|
|
|
(#)
|
|
|
(1)
|
|
|
(#)
|
|
|
(1)
|
|
Walter M. Higgins
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 08/04/2000
|
(2)
|
|
400,000
|
|
|
|
|
|
|
|
|
|
|
$
|
16.00
|
|
|
|
02/19/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 01/01/2001
|
(3)
|
|
110,130
|
|
|
|
|
|
|
|
|
|
|
$
|
14.80
|
|
|
|
01/02/2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 01/01/2002
|
(3)
|
|
123,900
|
|
|
|
|
|
|
|
|
|
|
$
|
15.58
|
|
|
|
01/02/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares -08/04/2006
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
435,000
|
|
|
$
|
7,321,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael W. Yackira
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2005
|
(3)
|
|
6,212
|
|
|
|
12,426
|
|
|
|
|
|
|
$
|
10.05
|
|
|
|
02/08/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2005
|
(5)
|
|
|
|
|
|
|
|
|
|
4,660
|
|
|
$
|
10.05
|
|
|
|
02/08/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2006
|
(3)
|
|
|
|
|
|
17,527
|
|
|
|
|
|
|
$
|
13.29
|
|
|
|
02/08/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares -02/07/2005
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,775
|
|
|
$
|
265,501
|
|
|
|
7,887
|
|
|
$
|
132,731
|
|
|
Performance Shares -02/07/2005
|
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,915
|
|
|
$
|
99,550
|
|
|
Performance Shares -02/07/2006
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,954
|
|
|
$
|
117,035
|
|
|
|
13,910
|
|
|
$
|
234,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paul J. Kaleta
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/01/2006
|
(8)
|
|
|
|
|
|
30,000
|
|
|
|
|
|
|
$
|
13.10
|
|
|
|
02/02/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2006
|
(3)
|
|
|
|
|
|
8,224
|
|
|
|
|
|
|
$
|
13.29
|
|
|
|
02/08/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2006
|
(5)
|
|
|
|
|
|
|
|
|
|
2,112
|
|
|
$
|
13.29
|
|
|
|
02/08/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2006
|
(3)
|
|
|
|
|
|
14,405
|
|
|
|
|
|
|
$
|
13.29
|
|
|
|
02/08/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares -02/07/2006
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,959
|
|
|
$
|
117,120
|
|
|
|
3,479
|
|
|
$
|
58,551
|
|
|
Performance Shares -02/07/2006
|
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,610
|
|
|
$
|
43,927
|
|
|
Performance Shares -02/07/2006
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,716
|
|
|
$
|
96,196
|
|
|
|
11,433
|
|
|
$
|
192,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Roberto R. Denis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2005
|
(3)
|
|
3,700
|
|
|
|
7,401
|
|
|
|
|
|
|
$
|
10.05
|
|
|
|
02/08/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2005
|
(5)
|
|
|
|
|
|
|
|
|
|
2,775
|
|
|
$
|
10.05
|
|
|
|
02/08/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2006
|
(3)
|
|
|
|
|
|
13,445
|
|
|
|
|
|
|
$
|
13.29
|
|
|
|
02/08/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares -02/07/2005
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,396
|
|
|
$
|
158,131
|
|
|
|
4,697
|
|
|
$
|
79,054
|
|
|
Performance Shares -02/07/2005
|
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,523
|
|
|
$
|
59,292
|
|
|
Performance Shares -02/07/2006
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,334
|
|
|
$
|
89,779
|
|
|
|
10,671
|
|
|
$
|
179,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey L. Ceccarelli
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 01/01/1998
|
(3)
|
|
7,920
|
|
|
|
|
|
|
|
|
|
|
$
|
24.93
|
|
|
|
01/02/2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 01/01/1999
|
(3)
|
|
7,920
|
|
|
|
|
|
|
|
|
|
|
$
|
24.22
|
|
|
|
01/02/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 08/01/1999
|
(9)
|
|
10,300
|
|
|
|
|
|
|
|
|
|
|
$
|
26.00
|
|
|
|
08/02/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 01/01/2001
|
(3)
|
|
22,510
|
|
|
|
|
|
|
|
|
|
|
$
|
14.80
|
|
|
|
01/02/2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 01/01/2002
|
(3)
|
|
34,500
|
|
|
|
|
|
|
|
|
|
|
$
|
15.58
|
|
|
|
01/02/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2005
|
(3)
|
|
4,842
|
|
|
|
9,685
|
|
|
|
|
|
|
$
|
10.05
|
|
|
|
02/08/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2005
|
(5)
|
|
|
|
|
|
|
|
|
|
3,632
|
|
|
$
|
10.05
|
|
|
|
02/08/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options - 02/07/2006
|
(3)
|
|
|
|
|
|
14,886
|
|
|
|
|
|
|
$
|
13.29
|
|
|
|
02/08/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares -02/07/2005
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,295
|
|
|
$
|
206,930
|
|
|
|
6,147
|
|
|
$
|
103,449
|
|
|
Performance Shares -02/07/2005
|
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,611
|
|
|
$
|
77,603
|
|
|
Performance Shares -02/07/2006
|
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,906
|
|
|
$
|
99,399
|
|
|
|
11,814
|
|
|
$
|
198,828
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Market Value is based on the December 31, 2006, closing trading price of SPR
stock of $16.83; all incentive plan performance share awards are shown as
achieving the target level of performance, which results in a 100% payout of the
award.
|
|
|
|
|
(2)
|
|
This grant vests over a four year period, one quarter each year beginning one year
after grant date.
|
|
|
|
|
(3)
|
|
These option awards vest over a three year period, one third each year beginning one
year after grant date.
|
|
|
|
|
(4)
|
|
Mr. Higgins was awarded 500,000 shares upon signing a new employment agreement in
August 2006. These shares are to be earned upon the achievement of certain objectives
prior to the expiration of the employment agreement in June 2008. Details of the
performance criteria to be met are included in Footnote 1 to the “Grants of Plan-Based
Awards” table.
|
|
|
|
|
(5)
|
|
This grant will be earned upon the restoration of SPR’s common stock dividend within
five years of grant date.
|
|
|
|
|
(6)
|
|
These performance share awards are paid at the end of a three year performance period
(measured from the date of grant) if the specified performance measures are achieved.
|
|
|
|
|
(7)
|
|
This grant will be earned upon the return of NPC and SPPC to investment grade within
three years of the award.
|
|
|
|
|
(8)
|
|
This award was granted to Mr. Kaleta upon his hire in 2006 and will vest at the end
of one year from date of grant.
|
|
|
|
|
(9)
|
|
This award was granted to Mr. Ceccarelli upon the consummation of the merger between
SPR and NPC, and vested one third each year over a three year period commencing January
2000.
|
191
OPTION EXERCISES AND STOCK VESTED
The following table provides information on the exercises of options and the vesting of stock
awards during 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPTION AWARDS
|
|
STOCK AWARDS
|
|
|
|
Number of Shares
|
|
Value Realized on
|
|
Number of Shares
|
|
Value Realized on
|
|
|
|
Acquired on
|
|
Exercise ($)
|
|
Acquired on
|
|
Vesting ($)
|
|
Name
|
|
Exercise (#)
|
|
(1)
|
|
Vesting (#)
|
|
(2)
|
|
|
|
Walter M. Higgins
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares
|
|
|
|
|
|
|
|
|
|
|
65,000
|
|
|
$
|
982,150
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
42,300
|
|
|
$
|
711,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael W. Yackira
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
|
|
|
30,000
|
|
|
$
|
300,450
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
12,544
|
|
|
$
|
211,116
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
39,894
|
|
|
$
|
671,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paul J. Kaleta
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
5,643
|
|
|
$
|
94,972
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Roberto R. Denis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
|
|
|
25,000
|
|
|
$
|
270,740
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
3,334
|
|
|
$
|
44,676
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
7,600
|
|
|
$
|
127,908
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
25,931
|
|
|
$
|
436,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey L. Ceccarelli
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
11,270
|
|
|
$
|
189,674
|
|
|
Restricted Shares
|
|
|
|
|
|
|
|
|
|
|
33,245
|
|
|
$
|
559,513
|
|
|
|
|
|
|
(1)
|
|
The value realized on exercise is calculated as the
fair market value on the date of exercise, less the exercise price
of the option.
|
|
|
|
(2)
|
|
The value realized on vesting is calculated as the
market value on the vesting date.
|
192
PENSION BENEFITS
The following table provides the present value of accumulated retirement benefits payable to
each of the named executive officers, according to the terms and conditions of each plan. The
retirement plans under which these benefits are available are generally described in the
Compensation Discussion and Analysis section of this note.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
Years
|
|
Present Value of
|
|
Payments
|
|
|
|
|
|
Credited
|
|
Accumulated
|
|
During Last
|
|
Name
|
|
Plan Name
|
|
Service
|
|
Benefit
|
|
Fiscal Year
|
|
|
|
Walter M. Higgins (1)
|
|
SPR Retirement Plan
|
|
|
10.250
|
|
|
$
|
401,006
|
|
|
$
|
—
|
|
|
|
|
SPR Restoration Plan
|
|
|
10.250
|
|
|
$
|
1,902,151
|
|
|
$
|
—
|
|
|
|
|
SPR SERP Plan
|
|
|
15.167
|
|
|
$
|
5,119,017
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael W. Yackira (2)
|
|
SPR Retirement Plan
|
|
|
3.667
|
|
|
$
|
107,353
|
|
|
$
|
—
|
|
|
|
|
SPR Restoration Plan
|
|
|
3.667
|
|
|
$
|
163,656
|
|
|
$
|
—
|
|
|
|
|
SPR SERP Plan
|
|
|
3.667
|
|
|
$
|
240,339
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paul J. Kaleta (3)
|
|
SPR Retirement Plan
|
|
|
0.667
|
|
|
$
|
17,571
|
|
|
$
|
—
|
|
|
|
|
SPR Restoration Plan
|
|
|
0.667
|
|
|
$
|
5,490
|
|
|
$
|
—
|
|
|
|
|
SPR SERP Plan
|
|
|
0.667
|
|
|
$
|
18,494
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Roberto R. Denis (4)
|
|
SPR Retirement Plan
|
|
|
3.083
|
|
|
$
|
96,097
|
|
|
$
|
—
|
|
|
|
|
SPR Restoration Plan
|
|
|
3.083
|
|
|
$
|
101,882
|
|
|
$
|
—
|
|
|
|
|
SPR SERP Plan
|
|
|
6.083
|
|
|
$
|
505,277
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey L. Ceccarelli (5)
|
|
SPR Retirement Plan
|
|
|
31.000
|
|
|
$
|
779,706
|
|
|
$
|
—
|
|
|
|
|
SPR Restoration Plan
|
|
|
31.000
|
|
|
$
|
657,860
|
|
|
$
|
—
|
|
|
|
|
SPR SERP Plan
|
|
|
32.083
|
|
|
$
|
570,835
|
|
|
$
|
—
|
|
|
|
|
|
|
(1)
|
|
Mr. Higgins’ benefit under the SERP plan includes 4
years, 11 months of imputed service.
|
|
|
|
(2)
|
|
Mr. Yackira will become vested in all plans in 1
year, 4 months.
|
|
|
|
(3)
|
|
Mr. Kaleta will become vested in all plans in 4
years, 4 months.
|
|
|
|
(4)
|
|
Mr. Denis’ benefit under the SERP plan includes 3
years of imputed service for attaining age 62; he will be vested in all
plans in 1 year, 11 months.
|
|
|
|
(5)
|
|
Mr. Ceccarelli’s benefit under the SERP plan includes
1 year, 1 month of imputed service.
|
The following assumptions were used in calculating the present value of the accumulated
benefit:
|
|
i.
|
|
Pension economic assumptions utilized for SPR’s FAS 158 financial reporting for fiscal
year 2006, were used for the calculations.
|
|
|
|
|
ii.
|
|
SPR reports using an early measurement date of September 30 and that date has been used
in all calculations for the above table, and these assumptions are outlined below:
|
|
|
a.
|
|
The discount rate was 6.0% for 2006
|
|
|
|
|
b.
|
|
Postretirement mortality is based on the RP 2000 mortality table,
projected to 2015
|
|
|
|
|
c.
|
|
There was assumed to be no pre-retirement mortality, turnover, or
disability
|
|
|
|
|
d.
|
|
Retirement age was assumed to be the greater of age 62 and current age
|
|
|
iii.
|
|
The demographic assumptions used are also consistent with pension financial reporting,
with the exception as required by SEC guidance, that pre-retirement decrements are not
used.
|
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE-IN-CONTROL
The following tables show the estimated payments each of the named executives could receive
upon their termination or a change-in-control, according to the terms and conditions of any
contracts or agreements in effect for that executive. The amounts shown assume that the
termination was effective as of December 31, 2006, and includes amounts earned through that time.
The actual amounts to be paid out can only be determined at the time an executive separates from
SPR.
193
The footnotes are presented after the final table.
Walter M. Higgins
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reason for Termination
|
|
|
|
|
Voluntary
|
|
|
For Cause
|
|
|
Death
|
|
|
Disability
|
|
|
Retirement
|
|
|
Without
|
|
|
Change-in-
|
|
|
Type of Benefit
|
|
(1) (8)
|
|
|
(2) (9)
|
|
|
(9)
|
|
|
(3) (9)
|
|
|
(4)
|
|
|
Cause (5) (10)
|
|
|
Control (6) (11)
|
|
|
|
|
Cash Severance (7)
|
|
$
|
1,687,500
|
|
|
$
|
—
|
|
|
$
|
562,500
|
|
|
$
|
562,500
|
|
|
$
|
1,687,500
|
|
|
$
|
1,312,500
|
|
|
$
|
2,625,000
|
|
|
Life Insurance
Proceeds (18)
|
|
|
|
|
|
|
|
|
|
$
|
2,750,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash LTIP Award
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lump Sum Pension Equivalent (16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Benefits(12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares
|
|
$
|
1,144,659
|
|
|
|
|
|
|
$
|
1,144,659
|
|
|
$
|
1,144,659
|
|
|
$
|
1,144,659
|
|
|
$
|
1,144,659
|
|
|
$
|
7,321,050
|
|
|
Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
401k Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unexercisable Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Benefits (13) (17)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR Retirement Plan
|
|
$
|
36,216
|
|
|
|
|
|
|
$
|
18,108
|
|
|
$
|
36,216
|
|
|
$
|
36,216
|
|
|
$
|
36,216
|
|
|
$
|
36,216
|
|
|
SPR Restoration Plan
|
|
$
|
169,284
|
|
|
|
|
|
|
$
|
84,636
|
|
|
$
|
169,284
|
|
|
$
|
169,284
|
|
|
$
|
169,284
|
|
|
$
|
169,284
|
|
|
SPR SERP Plan
|
|
$
|
447,984
|
|
|
|
|
|
|
$
|
223,992
|
|
|
$
|
447,984
|
|
|
$
|
447,984
|
|
|
$
|
447,984
|
|
|
$
|
447,984
|
|
|
Retiree Medical
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested Deferred Compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health & Welfare (14)
|
|
$
|
52,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
114,429
|
|
|
$
|
72,599
|
|
|
Outplacement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perquisites
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax Gross-Ups (15)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,813,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total of All
Benefits (19)
|
|
$
|
3,538,363
|
|
|
$
|
—
|
|
|
$
|
4,783,895
|
|
|
$
|
2,360,643
|
|
|
$
|
3,485,643
|
|
|
$
|
3,225,072
|
|
|
$
|
14,485,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael W. Yackira
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reason for Termination
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Without
|
|
|
Change-in-
|
|
|
|
|
Voluntary
|
|
|
For Cause
|
|
|
Death
|
|
|
Disability
|
|
|
Retirement
|
|
|
Cause (5)
|
|
|
Control (6)
|
|
|
Type of Benefit
|
|
(1) (8)
|
|
|
(2) (9)
|
|
|
(9)
|
|
|
(3) (9)
|
|
|
(4)
|
|
|
(10)
|
|
|
(11)
|
|
|
|
|
Cash Severance (7)
|
|
$
|
375,000
|
|
|
|
—
|
|
|
|
—
|
|
|
$
|
375,000
|
|
|
$
|
375,000
|
|
|
$
|
375,000
|
|
|
$
|
1,687,500
|
|
|
Life Insurance Proceeds (18)
|
|
|
|
|
|
|
|
|
|
$
|
1,063,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash LTIP Award
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lump Sum Pension Equivalent (16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,192,714
|
|
|
Equity Benefits(12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares
|
|
$
|
1,132,161
|
|
|
|
|
|
|
$
|
1,132,161
|
|
|
$
|
1,132,161
|
|
|
$
|
1,132,161
|
|
|
$
|
1,132,161
|
|
|
$
|
1,520,338
|
|
|
Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
401k Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unexercisable Options
|
|
$
|
177,891
|
|
|
|
|
|
|
$
|
177,891
|
|
|
$
|
177,891
|
|
|
$
|
177,891
|
|
|
$
|
177,891
|
|
|
$
|
177,891
|
|
|
Retirement Benefits (13) (17)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR Retirement Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8,016
|
|
|
$
|
8,016
|
|
|
SPR Restoration Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,472
|
|
|
$
|
11,472
|
|
|
SPR SERP Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
18,312
|
|
|
$
|
18,312
|
|
|
Retiree Medical
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested Deferred Compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health & Welfare (14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
65,362
|
|
|
Outplacement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perquisites
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax Gross-Ups (15)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total of All
Benefits (19)
|
|
$
|
1,685,052
|
|
|
$
|
—
|
|
|
$
|
2,373,052
|
|
|
$
|
1,685,052
|
|
|
$
|
1,685,052
|
|
|
$
|
1,722,852
|
|
|
$
|
4,681,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
194
Paul J. Kaleta
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reason for Termination
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Without
|
|
|
Change-in-
|
|
|
|
|
Voluntary
|
|
|
For Cause
|
|
|
Death
|
|
|
Disability
|
|
|
Retirement
|
|
|
Cause (5)
|
|
|
Control (6)
|
|
|
Type of Benefit
|
|
(1) (8)
|
|
|
(2) (9)
|
|
|
(9)
|
|
|
(3) (9)
|
|
|
(4)
|
|
|
(10)
|
|
|
(11)
|
|
|
|
|
Cash Severance (7)
|
|
$
|
300,000
|
|
|
|
—
|
|
|
|
—
|
|
|
$
|
300,000
|
|
|
$
|
300,000
|
|
|
$
|
300,000
|
|
|
$
|
1,305,000
|
|
|
Life Insurance
Proceeds (18)
|
|
|
|
|
|
|
|
|
|
$
|
850,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash LTIP Award
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lump Sum Pension Equivalent (16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
523,994
|
|
|
Equity Benefits(12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares
|
|
$
|
329,182
|
|
|
|
|
|
|
$
|
329,182
|
|
|
$
|
329,182
|
|
|
$
|
329,182
|
|
|
$
|
329,182
|
|
|
$
|
603,187
|
|
|
Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
401k Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unexercisable Options
|
|
$
|
199,483
|
|
|
|
|
|
|
$
|
199,483
|
|
|
$
|
199,483
|
|
|
$
|
199,483
|
|
|
$
|
199,483
|
|
|
$
|
199,483
|
|
|
Retirement Benefits (13) (17)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR Retirement Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,920
|
|
|
$
|
1,920
|
|
|
SPR Restoration Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
696
|
|
|
$
|
696
|
|
|
SPR SERP Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,052
|
|
|
$
|
2,052
|
|
|
Retiree Medical
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested Deferred Compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health & Welfare (14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
58,406
|
|
|
Outplacement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perquisites
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax Gross-Ups (15)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total of All
Benefits (19)
|
|
$
|
828,665
|
|
|
$
|
—
|
|
|
$
|
1,378,665
|
|
|
$
|
828,665
|
|
|
$
|
828,665
|
|
|
$
|
833,333
|
|
|
$
|
2,694,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Roberto R. Denis
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reason for Termination
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Without
|
|
|
Change-in-
|
|
|
|
|
Voluntary
|
|
|
For Cause
|
|
|
Death
|
|
|
Disability
|
|
|
Retirement
|
|
|
Cause (5)
|
|
|
Control (6)
|
|
|
Type of Benefit
|
|
(1) (8)
|
|
|
(2) (9)
|
|
|
(9)
|
|
|
(3) (9)
|
|
|
(4)
|
|
|
(10)
|
|
|
(11)
|
|
|
|
|
Cash Severance (7)
|
|
$
|
300,000
|
|
|
|
—
|
|
|
|
—
|
|
|
$
|
300,000
|
|
|
$
|
300,000
|
|
|
$
|
300,000
|
|
|
$
|
1,350,000
|
|
|
Life Insurance
Proceeds (18)
|
|
|
|
|
|
|
|
|
|
$
|
850,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash LTIP Award
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lump Sum Pension Equivalent (16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,202,928
|
|
|
Equity Benefits(12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares
|
|
$
|
1,069,769
|
|
|
|
|
|
|
$
|
1,069,769
|
|
|
$
|
1,069,769
|
|
|
$
|
1,069,769
|
|
|
$
|
1,069,769
|
|
|
$
|
1,404,043
|
|
|
Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
401k Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unexercisable Options
|
|
$
|
191,220
|
|
|
|
|
|
|
$
|
191,220
|
|
|
$
|
191,220
|
|
|
$
|
191,220
|
|
|
$
|
191,220
|
|
|
$
|
191,220
|
|
|
Retirement Benefits (13) (17)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR Retirement Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8,232
|
|
|
$
|
8,232
|
|
|
SPR Restoration Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7,632
|
|
|
$
|
7,632
|
|
|
SPR SERP Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
13,500
|
|
|
$
|
13,500
|
|
|
Retiree Medical
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested Deferred Compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health & Welfare (14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
58,406
|
|
|
Outplacement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perquisites
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax Gross-Ups (15)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total of All
Benefits (19)
|
|
$
|
1,560,989
|
|
|
$
|
—
|
|
|
$
|
2,110,989
|
|
|
$
|
1,560,989
|
|
|
$
|
1,560,989
|
|
|
$
|
1,590,353
|
|
|
$
|
4,235,961
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
195
Jeffrey L. Ceccarelli
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reason for Termination
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Without
|
|
|
Change-in-
|
|
|
|
|
Voluntary
|
|
|
For Cause
|
|
|
Death
|
|
|
Disability
|
|
|
Retirement
|
|
|
Cause (5)
|
|
|
Control (6)
|
|
|
Type of Benefit
|
|
(1) (8)
|
|
|
(2) (9)
|
|
|
(9)
|
|
|
(3) (9)
|
|
|
(4)
|
|
|
(10)
|
|
|
(11)
|
|
|
|
|
Cash Severance (7)
|
|
$
|
335,000
|
|
|
|
—
|
|
|
|
—
|
|
|
$
|
335,000
|
|
|
$
|
335,000
|
|
|
$
|
335,000
|
|
|
$
|
1,507,500
|
|
|
Life Insurance
Proceeds (18)
|
|
|
|
|
|
|
|
|
|
$
|
1,003,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash LTIP Award
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lump Sum Pension Equivalent (16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
343,276
|
|
|
Equity Benefits(12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Shares
|
|
$
|
925,689
|
|
|
|
|
|
|
$
|
925,689
|
|
|
$
|
925,689
|
|
|
$
|
925,689
|
|
|
$
|
925,689
|
|
|
$
|
1,245,723
|
|
|
Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
401k Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unexercisable Options
|
|
$
|
142,990
|
|
|
|
|
|
|
$
|
142,990
|
|
|
$
|
142,990
|
|
|
$
|
142,990
|
|
|
$
|
142,990
|
|
|
$
|
142,990
|
|
|
Retirement Benefits (13) (17)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR Retirement Plan
|
|
$
|
60,876
|
|
|
|
|
|
|
$
|
52,476
|
|
|
$
|
60,876
|
|
|
$
|
60,876
|
|
|
$
|
60,876
|
|
|
$
|
60,876
|
|
|
SPR Restoration Plan
|
|
$
|
51,372
|
|
|
|
|
|
|
$
|
44,292
|
|
|
$
|
51,372
|
|
|
$
|
51,372
|
|
|
$
|
51,372
|
|
|
$
|
51,372
|
|
|
SPR SERP Plan
|
|
$
|
42,972
|
|
|
|
|
|
|
$
|
37,044
|
|
|
$
|
42,972
|
|
|
$
|
42,972
|
|
|
$
|
42,972
|
|
|
$
|
42,972
|
|
|
Retiree Medical
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested Deferred Compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health & Welfare (14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
61,761
|
|
|
Outplacement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perquisites
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax Gross-Ups (15)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total of All Benefits (19)
|
|
$
|
1,558,899
|
|
|
$
|
—
|
|
|
$
|
2,205,491
|
|
|
$
|
1,558,899
|
|
|
$
|
1,558,899
|
|
|
$
|
1,558,899
|
|
|
$
|
3,456,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Voluntary Termination
is defined for Mr. Higgins consistent with his employment
agreement dated August 4, 2006. The document provides for a benefit equal to continued
salary through June 1, 2008, provided he voluntarily resigns with the Board’s consent
prior to June 1, 2008. In addition, he would be eligible to receive a pro-rata payment
for all Short Term Incentive Awards, which equals 75% of base pay for 2006, and which otherwise would have been earned but unpaid
by that date. For each of the other named executives, Voluntary Termination is defined
as the executive resigning for good cause consistent with the terms of his employment
agreement.
|
|
|
|
(2)
|
|
Termination For Cause
requires SPR to terminate the employment relationship based
on one of the provisions of the most recent employment agreement, such as fraud or gross
misconduct.
|
|
|
|
(3)
|
|
Termination on the basis of
Disability
assumes the disability prevents the
executive from successfully fulfilling the duties of his position. This calculation
assumes the qualifying event occurred on or before June 1, 2006, that SPR gave 30 days
notice of termination, and the termination was effective December 31, 2006. Also for
purposes of this calculation, it has been assumed that the CEO does not exercise the
appeal provision of the disability determination process.
|
|
|
|
(4)
|
|
Termination on the basis of
Retirement
assumes that the executive voluntarily
resigned and is eligible to retire effective December 31, 2006.
|
|
|
|
(5)
|
|
Termination Without Cause
requires SPR to decide to terminate the employment
relationship without notice or providing a reason.
|
|
|
|
(6)
|
|
The
Change-in-Control
calculation assumes that the executive was terminated at
some point following a corporate change-in-control with an effective date of December
31, 2006.
|
|
|
|
(7)
|
|
Cash Severance is defined as all those payments owed or owing to the executive
which are payable in cash under the different termination scenarios. While different
payments may be paid in a lump sum or over a period of time, for the purpose of these
calculations, the payments are assumed to be made in a lump sum within five days of the
termination date. In addition, it is assumed that all accrued and unused vacation time
for 2006 has been either used or paid, and all salary has been paid through the last day
of the year.
|
|
|
|
(8)
|
|
The value of Mr. Higgins’ Cash Severance following a Voluntary Termination has
been set at 1.5 times his annual base salary and target annual bonus award. As per
footnote 1, by agreement, Mr. Higgins is eligible for continued salary payments through
June 1, 2008, if he were to voluntarily resign with the Board’s Consent effective
December 31, 2006. For all other executives, the value is calculated based on the
formula of one times annual base salary.
|
|
|
|
(9)
|
|
In relation to the Cash Severance for Death, Disability or For Cause, the amount
represents the executive’s pro-rata portion of his annual incentive award, which for
2006 had a performance period end date of December 31, 2006. Therefore, the payment of
the annual incentive award would be earned but unpaid on December 31, 2006, provided any
annual incentive performance measures were fulfilled. For purposes of this calculation,
it is assumed the executive fulfilled the performance measures at “target” in relation
to any annual incentive award.
|
|
|
|
(10)
|
|
The value of the Cash Severance for Termination without Cause represents one-time
base annual earnings plus target incentive award.
|
|
|
|
(11)
|
|
The value of the Cash Severance for termination following a Change-in-Control,
represents two times base earnings plus target annual bonus award, as per Mr. Higgins’
most recent employment agreement. For all other named executive officers the values
represent three times the annual base earnings plus the target annual bonus award.
|
|
|
|
(12)
|
|
Equity awards are valued based on the trading price of SPR’s common stock at
close of business on December 31, 2006 of $16.83. In addition, the calculations reflect
any provisions in the employment or change-in-control agreements, in regard to
accelerated vesting of outstanding performance or other share awards, as well as the
immediate right to exercise any outstanding and unvested stock options. The values are
based on the assumption that any unvested portion of performance shares would have been
vested had the performance cycle not been truncated. Also, any pro-rata calculations
are based on the initial grant date from the start of the performance cycle through
December 31, 2006.
|
|
|
|
(13)
|
|
The value of any retirement benefits is calculated as the amount of any projected
single life annuity for one year at the executive’s normal retirement, or the first date
he would be eligible to receive an unreduced benefit. The value shown reflects the
amount of any benefit accrued as of December 31, 2006, and assumes the executive
voluntarily terminates employment on that date to retire. The following assumptions were listed for this calculation:
|
|
|
|
|
|
|
|
i.
|
|
Annuity conversion interest rate was 4.73% for 2006.
|
|
|
ii.
|
|
The mortality table used for lump sum conversions was GAR 94 Unisex.
|
|
|
iii.
|
|
Retirement age was assumed to be the greater of age 55 and current age.
|
|
|
|
|
|
|
|
(14)
|
|
The value of the health and welfare benefits to be provided to an executive and
his family, if appropriate, is based on the value of his current elections prior to
termination. The calculation assumes no change in benefit elections over the span of any
continuation period. For each of the named
|
196
|
|
|
|
|
|
|
executives, except Mr. Higgins, the
opportunity to continue in the health program, at the full cost and expense of SPR,
beyond employment, is available for up to 36 months following a change-in-control. Mr.
Higgins is only eligible for an additional 24 months following a change-in-control, as
per his most recent employment agreement. However, Mr. Higgins is eligible for continued
participation through June 1, 2008, provided he voluntarily resigns with the Board’s
consent, and in the event of termination without cause, Mr. Higgins is eligible for
continued coverage for up to 36 months.
|
|
|
|
(15)
|
|
Mr. Higgins is the only named executive who is eligible for a gross-up of any
severance payments following a change-in-control, based on calculations for parachute
payments. All of the other executives’ severance payments are subject to reduction in
the event the payment exceeds the threshold for parachute payments, set by IRC Section
280(g), which is defined as 2.99 times his 5 year average W-2 earnings for the 5 years
immediately prior to termination. For purposes of these calculations, these values
represent the maximum amount payable to each executive which would then be subject to
reduction at the time of termination.
|
|
|
|
(16)
|
|
The Lump Sum Pension Service Equivalent is based on the provisions of each named
executive’s employment or change-in-control agreement, which provides for a lump sum
cash payment equal to the actuarial equivalent of three additional years of service,
calculated from the date of termination, under all pension plans. In the case of Mr.
Higgins, the value of this benefit is equal to zero since any grant for additional years
of service under the plan, would not enhance his already accrued and vested benefit
based on his current age and eligibility to retire.
|
|
|
|
(17)
|
|
In addition, each of the named executives would be eligible to receive:
|
|
|
a.
|
|
All fully vested amounts, which might be distributable consistent
with the law, under SPR’s Non-qualified deferred compensation program, as
presented in the “Non-Qualified Deferred Compensation” table
|
|
|
|
|
b.
|
|
All fully vested amounts under SPR’s 401(k) defined contribution
plan, which all employees participate in; the 2006 contribution for each named
executive is included in the “Summary Compensation Table”.
|
|
|
|
|
|
|
|
(18)
|
|
Each named executive officer is covered by SPR’s Basic Life Insurance Program
through CIGNA (1.5 times salary), and an Executive Life Insurance Program through
Paragon with benefits payable to a designated beneficiary in the event of death ranging
from $400,000 to $500,000. In addition to the basic amounts, SPR provides for
accidental death and dismemberment coverage (1.5 times salary) and business travel
accident insurance of $1,000,000 for each of the named executive officers with the
exception of Mr. Higgins. In regard to Mr. Higgins, SPR contracts directly with CIGNA
and Paragon to provide coverage and pays the premium on a policy with Pacific Life
Insurance Company as well as a policy administered by M. Benefits Solutions. For the
purpose of these calculations the qualifying event for each named executive is assumed to
be for natural causes at December 31, 2006, and not as part of any business travel or
accident.
|
|
|
|
(19)
|
|
This total includes values for annuities that were calculated for retirement benefits that are payable monthly over a period
of time, that may or may not be realized at the values disclosed.
|
197
NON-QUALIFIED DEFERRED COMPENSATION
The following table shows the 2006 activity and ending balances for each of the named
executive officers in the SPR non-qualified deferred compensation plan. This plan is generally
described in the Compensation Discussion and Analysis section of this note.
NON-QUALIFIED DEFERRED COMPENSATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
Executive
|
|
|
Registrant
|
|
|
|
|
|
|
Withdrawals/
|
|
|
|
|
|
|
|
Contributions in
|
|
|
Contribution in
|
|
|
Aggregate
|
|
|
Distributions in
|
|
|
Aggregate Balance
|
|
|
|
|
Last Fiscal Year
|
|
|
Last Fiscal Year
|
|
|
Earnings in Last
|
|
|
Last Fiscal Year
|
|
|
at Last Fiscal Year-
|
|
|
Name
|
|
($)
|
|
|
($)
|
|
|
Fiscal Year ($)
|
|
|
($)
|
|
|
End ($)
|
|
|
Walter M. Higgins
|
|
|
42,175
|
|
|
|
—
|
|
|
|
3,576
|
|
|
|
—
|
|
|
|
45,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael W. Yackira
|
|
|
18,000
|
|
|
|
—
|
|
|
|
4,724
|
|
|
|
—
|
|
|
|
38,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paul J. Kaleta
|
|
|
5,004
|
|
|
|
—
|
|
|
|
72
|
|
|
|
—
|
|
|
|
5,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Roberto R. Denis
|
|
|
8,190
|
|
|
|
—
|
|
|
|
584
|
|
|
|
—
|
|
|
|
8,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey L. Ceccarelli
|
|
|
12,900
|
|
|
|
—
|
|
|
|
1,033
|
|
|
|
—
|
|
|
|
13,933
|
|
The 2006 Registrant Contribution will be made in early 2007.
2006
COMPENSATION OF NON-EMPLOYEE DIRECTORS
The total 2006 compensation of our Non-Employee Directors is shown in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
|
|
|
|
|
|
|
|
Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Value
|
|
|
|
|
|
|
|
Earned or
|
|
|
|
|
|
|
|
|
|
Non-Equity
|
|
and Nonqualified
|
|
|
|
|
|
|
|
Paid in
|
|
Stock
|
|
Option
|
|
Incentive Plan
|
|
Deferred
|
|
All Other
|
|
|
|
|
|
Cash
|
|
Awards
|
|
Awards
|
|
Compensation
|
|
Compensation
|
|
Compensation
|
|
Total
|
|
Name
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
Earnings
|
|
($)
|
|
($)
|
|
|
|
Mr. Anderson
|
|
$
|
50,809
|
|
|
$
|
35,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
$
|
85,809
|
|
|
Ms. Coleman
|
|
|
43,609
|
|
|
|
35,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
78,609
|
|
|
Ms. Corbin
|
|
|
46,609
|
|
|
|
35,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
81,609
|
|
|
Mr. Day* (1)
|
|
|
39,200
|
|
|
|
35,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
74,200
|
|
|
Mr. Donnelley*
|
|
|
35,513
|
|
|
|
57,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
92,513
|
|
|
Mr. Herbst *
|
|
|
45,809
|
|
|
|
35,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
80,809
|
|
|
Mr. O’Reilly * (1)
|
|
|
24,800
|
|
|
|
57,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
81,800
|
|
|
Mr. Satre * (1)
|
|
|
39,800
|
|
|
|
57,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
96,800
|
|
|
Mr. Snyder (1)
|
|
|
56,200
|
|
|
|
35,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
91,200
|
|
|
Mr. Turner* (1)
|
|
|
57,200
|
|
|
|
35,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
92,200
|
|
|
|
|
|
|
*
|
|
Chair of Committee
|
|
|
|
(1)
|
|
The Director elected to defer payment of the stock award until
such time as he is no longer a Director of SPR, although the receipt of the
stock award is reflected in the Stock Awards column.
|
DIRECTOR COMPENSATION
Each non-employee director is paid an annual retainer of $57,000. In keeping with the Board’s
policy to tie management and director compensation to overall company performance and to increase
director share ownership, SPR’s Non-Employee Director Stock Plan (“Plan”) requires that a minimum
of $35,000 of the annual retainer for each non-employee director be paid in common stock of SPR.
In accordance with the terms of the Plan, several non-employee directors regularly elect to receive
an even greater percentage in stock. The reason for instituting a minimum amount of annual
retainer that non-employee directors must be paid in SPR Stock is to ensure that all non-employee
directors will hold a minimum of $100,000 worth of SPR Stock after their first three-year term in
office.
In addition to the annual retainer, non-employee directors of SPR and its subsidiaries are
paid $1,200 for each Board or Committee meeting attended (other than Audit Committee meetings,
addressed below), not to exceed two meeting fees per day regardless of the number of meetings
attended. Members of the Audit Committee are paid $1,500 per meeting of the Audit Committee
attended. Non-employee directors also receive a full or partial fee (depending on distance) for
travel to attend meetings away from the director’s home city. In consideration of their additional
responsibility and time commitments, non-employee directors serving as Committee Chairpersons are
also paid an additional $1,000 quarterly, except for the Audit Committee Chair, who receives $2,500
quarterly in consideration for the considerable duties now imposed by that office.
198
SPR’s Retirement Plan for Outside Directors, adopted March 6, 1987, was terminated on June 25,
1996. The actuarial value
of the vested benefit as of May 20, 1996, for each director was converted into “phantom stock”
of SPR at its fair market value on that day. The “phantom stock” is held in an account to be paid
at the time of the non-employee director’s departure from the Board, either in stock or cash at the
discretion of the Board. All “phantom stock” earns dividends at the same rate as listed company
common stock from the date of conversion and is deemed reinvested in additional shares at the price
of the stock on the dividend payment date.
BOARD AND COMMITTEE MEETINGS
The Board of Directors maintains the following committees: Audit; Compensation; Corporate and
Civic Responsibility; Nominating and Governance; and Planning and Finance. The Board also
establishes ad hoc committees for specific projects when required.
The Audit Committee was established in July 1992 to review and confer with SPR’s independent
auditors and to review its internal auditing program and procedures and its financial statements to
ensure that SPR’s operations and financial reporting are in compliance with all applicable laws,
regulations, and SPR policies. The directors presently serving on the Audit Committee, all of whom
are “independent,” are Mr. Turner (Chair), Ms. Corbin, and Messrs. Satre and Snyder. The Audit
Committee met 8 times in 2006. The
membership and structure of the Audit Committee and its governing documents satisfy all
requirements of the SEC and the NYSE.
The Compensation Committee, formerly called the Human Resources Committee, was formed in July
1999 and assumed the duties of a pre-existing Compensation and Organization Committee, which was
originally formed in 1991. This Committee reviews director and executive performance, and reviews
and recommends to the Board any changes in fees for directors and compensation for all officers of
SPR. The Committee also oversees SPR’s pension and 401(k) benefit plans and monitors and oversees
the appointment and discharge of plan money managers. It also reviews and discharges the fiduciary
duties delegated by the Board to the Committee under SPR’s benefit plans. The Committee’s charter
is posted on SPR’s website at
www.sierrapacificresources.com
. The directors presently
serving on the Compensation Committee are Mr. Donnelley (Chair), Ms. Coleman, and Messrs. Anderson
and Day. The Compensation Committee met five times in 2006. All members of the Compensation
Committee are independent as defined in Sections 303A of the New York Stock Exchange Listed Company
Manual. No member of the Committee has any relationship with SPR that might interfere with the
exercise of independent judgment or overall independence from management of SPR.
The Corporate and Civic Responsibility Committee was formed in July 1999 and, among other
things, assumed the duties of the previous Environmental Committee, which was established in 1992.
Among its other duties, this Committee oversees the SPR’s environmental policy and performance and
provides guidance to executive management on environmental issues as well as overseeing all other
aspects of corporate compliance with applicable law, business standards of conduct, corporate
giving, and legislative and governmental affairs. The directors presently serving on the Corporate
and Civic Responsibility Committee are Mr. Day (Chair) and Messrs. Anderson, Higgins, Satre, Snyder
and Turner. The Corporate and Civic Responsibility Committee met three times in 2006.
The Nominating and Governance Committee, which was formed in August 2003, assumed certain
duties formerly discharged by the Human Resources Committee. All members of the Nominating and
Governance Committee are independent as defined in Section 303A
of the New York Stock Exchange Listed
Company Manual. No member of the Committee has any relationship with SPR that might interfere with
the exercise of independent judgment or overall independence from management of SPR. This
Committee considers nominations to the Board of Directors as recommended by or from a variety of
sources, including Board members, senior management, community and business leaders, and search
agencies to whom it has paid fees in the past and may continue to pay a fee. Although the Board
has not established any absolute prerequisites for membership, in seeking new directors the Board
values diversity, general business acumen, knowledge, and experience, specialized knowledge or
experience in our industry, and general familiarity with finance and accounting. The Committee
also considers candidates recommended by Stockholders. To be considered, nominations must be
submitted in writing to the Committee in care of the Secretary of SPR within the time frame fixed
by SPR’s Bylaws as reported in this proxy. Any stockholder submitting a recommendation should
include as much information as he or she deems appropriate for consideration by the Committee. The
Secretary will then submit the recommendation to the Committee for consideration at or before the
time the Committee makes its recommendations to the Board for nominees for the next Annual Meeting
of Stockholders. The Committee also recommends appointments of Directors to Board Committees and
reviews plans for management succession. Pursuant to New York Stock Exchange rules, the
Committee’s Charter and SPR’s Code of Business Conduct, and Corporate Governance Guidelines are
posted on SPR’s website at
www.sierrapacificresources.com
. The directors presently serving
on the Nominating and Governance Committee are Mr. Herbst (Chair), Ms. Corbin and Messrs. Anderson,
Satre, and Snyder. The Nominating and Governance Committee met five times in 2006. For the 2007
Annual Meeting, no institutional stockholder or group of stockholders put forward any nominees for
director.
The Planning and Finance Committee was formed in July 1999. This Committee reviews and
recommends the long-range goals of the parent and subsidiary companies to the Board, and the type
and amount of financing necessary to meet those goals. The directors presently serving on the
Planning and Finance Committee are Mr. O’Reilly (Chair), Ms. Coleman, and Messrs. Donnelly, Herbst
and Higgins. The Planning and Finance Committee met four times in 2006.
There were four regularly scheduled and three special meetings of the Board of Directors
during 2006. Each member of the Board attended at least 75% of all meetings of the Board of
Directors and of all Committees which he or she served, except for Mr. Day. Non-management
directors meet at regularly scheduled and unscheduled Executive Sessions during Board meetings
without
199
management present. James Donnelley, an independent director, was selected by the Board to
preside over these Executive Sessions.
COMPENSATION COMMITTEE
Compensation Committee Interlocks and Insider Participation
During 2006, Ms. Coleman, and Messrs. Anderson, Donnelley and Day served as members of the
Compensation Committee. None of them were at any time during 2006, or before then, an officer or
employee of SPR or any of its subsidiaries. None of them had any relationships with SPR or any of
its subsidiaries during 2006 that was required to be disclosed under Item 404 of Regulation S-K
under the Exchange Act.
None of our executive officers or any of our subsidiaries served as a director or member of
the Compensation Committee (or other committee serving an equivalent function) of any other entity,
whose executive officer served on our Board of Directors or any of our subsidiaries or the
Compensation Committee.
Compensation Committee Report
The Compensation Committee of the Board of Directors of SPR oversees SPR’s compensation
program on behalf of the Board. In fulfilling its oversight responsibilities, the Compensation
Committee reviewed and discussed with management the Compensation Discussion and Analysis set forth
in this Annual Report on Form 10-K for the fiscal year ended December 31, 2006.
In reliance on the review and discussions referred to above, the Compensation Committee
recommended to the Board that the Compensation Discussion and Analysis be included in this Annual
Report on Form 10-K for the fiscal year ended December 31, 2006 and SPR’s Proxy Statement to be
filed in connection with the SPR’s 2007 Annual Meeting of stockholders, each of which will be filed
with the SEC.
|
|
|
|
|
|
|
|
COMPENSATION COMMITTEE
James R. Donnelley,
Chair
Joseph B. Anderson, Jr.
Mary Lee Coleman
Theodore J. Day
|
|
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All of the common stock of NPC and SPPC is owned by SPR.
Information regarding security ownership of SPR common stock by
certain beneficial owners and management is hereby incorporated by reference from SPR’s definitive proxy statement to be filed
in connection with the annual meeting of shareholders to be held on May 7, 2007.
200
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Related Party Transactions
The son of John F. O’Reilly, a member of SPR’s Board of Directors, is associated with the
Waller Law Group, which is acting as co-counsel for SPR and the Utilities in two significant
litigation matters. Mr. O’Reilly’s son is not working on either matter, and neither Mr. O’Reilly
nor his son receives any compensation or other benefits from SPR or the Utilities related to these
matters. On the basis of this relationship, however, the Board of Directors has not included Mr. O’Reilly among those directors considered to be independent.
Affiliate Transactions and Relationships
Employees of SPR provide certain accounting, treasury, information technology and
administrative services to NPC and SPPC. The costs of those services are allocated among the
Utilities according to each Utility’s usage. For fiscal year 2006, the costs for such services
allocated to NPC was $2.2 million and the costs of such services allocated to SPPC was $1.7
million. Additionally, many of SPR’s officers are also officers of NPC and SPPC. All three
Companies have the same members of their respective boards of directors. SPR files a consolidated
federal income tax return for itself and its subsidiaries. Current income taxes are allocated
based on each entity’s respective taxable income or loss and investment tax credits as if each
subsidiary filed a separate return. SPR does not believe that any significant additional tax
liability would be incurred by any of its subsidiaries on behalf of any other subsidiary; however,
SPR and its subsidiaries could potentially incur certain tax liabilities as a result of the joint
tax filing in the event of a change in applicable law or as a result of an audit.
As part of their on-going cash management practices and operations, SPR may make intercompany
loans to the Utilities, subject to any applicable regulatory restrictions and restrictions under
SPR’s or the Utilities’ financing agreements.
Review, Approval or Ratification of Transactions with Related Parties
In accordance with SPR’s Business Conduct Code “The Power of Integrity—A Guide to Business
Conduct” (the “Business Conduct Code”), all transactions and relationships between and among the
Utilities and their non–utility affiliates, including SPR, are to be guided by and conducted in
accordance with all statutes and rules enforced by the PUCN and the California Public Utilities
Commission, FERC, and the related compliance plans of the Utilities. Employees must ensure that
inter-company transactions and related activities are permitted, properly documented and meet
applicable regulations. Moreover, SPR and the Utilities must comply with FERC Order No. 2004 and
all subsequent versions. This requires that employees engaged in transmission system operations
act independently of any company employees engaged in wholesale merchant functions so as not to
benefit an affiliate in the wholesale purchase and sale of power or natural gas. All directors,
officers, employees, consultants and contractors of SPR and the Utilities are expected to abide by
these standards of conduct and every supervisor and manager is responsible for helping employees
understand and comply with these principles. “The Power of Integrity—A Guide to Business Conduct”
is set forth in writing on SPR’s website at
www.sierrapacificresources.com
.
The Ethics and Compliance Office oversees company compliance with laws, regulations and
policies, self–governance activities, compliance risk assessment, integrity and compliance
training, and monitors and reports on compliance efforts. The Ethics and Compliance Office is
responsible for managing all integrity and compliance programs, including managing the
investigation process and reviewing results of investigations. The Ethics and Compliance Office is
also responsible for applying the business conduct rules on a consistent basis and ensuring that
employee concerns are addressed in a fair, unbiased and timely manner.
The Code of Ethics for the CEO, CFO and Controller (the “Code of Ethics”) is set forth in
writing on SPR’s website at
www.sierrapacificresources.com
. This Code of Ethics requires
the CEO, CFO and Controller to exhibit and promote the highest standards of honest and ethical
conduct at SPR and the Utilities through the establishment and operation of policies and procedures
that, among other things, prohibit and eliminate the appearance or occurrence of conflicts between
what is in the best interest of SPR and the Utilities and what could result in material personal
gain for a member of the financial organization, including the CEO, CFO and Controller.
In accordance with the charter of SPR’s audit committee, the audit committee is responsible
for reviewing reports and disclosures of insider and affiliated party transactions and periodically
reviewing the Code of Ethics to determine whether it complies with applicable rules and regulations
and whether management has established a system to enforce the code. The audit committee is also
responsible for advising the Board with respect to SPR’s policies and procedures regarding
compliance with applicable laws and regulations in connection with insider and affiliated party
transactions as well as compliance with the Business Conduct Code. A copy of the audit committee
charter is set forth in writing on SPR’s website at
www.sierrapacificresources.com
.
201
BOARD
INDEPENDENCE AND CORPORATE GOVERNANCE DISCLOSURE
Director Independence
The Board has determined that each of the following directors of SPR meet the independence
requirements under the New York Stock Exchange’s listing standards: Mary Lee Coleman, Theodore J.
Day, Jerry E. Herbst, Donald D. Snyder, Clyde T. Turner, Philip G. Satre, Krestine M. Corbin,
Joseph B. Anderson, Jr., James R. Donnelley and Brian J. Kennedy.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following table summarizes the aggregate fees billed to SPR, NPC and SPPC by our
independent registered public accounting firm, Deloitte and Touche LLP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPC
|
|
|
SPPC
|
|
|
SPR
Consolidated (d)
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Audit Fees (a)
|
|
$
|
1,403,150
|
|
|
$
|
1,359,499
|
|
|
$
|
1,328,825
|
|
|
$
|
1,295,521
|
|
|
$
|
3,016,025
|
|
|
$
|
3,270,514
|
|
|
Audit Related Fees (b)
|
|
|
10,000
|
|
|
|
—
|
|
|
|
10,500
|
|
|
|
36,308
|
|
|
|
20,500
|
|
|
|
94,693
|
|
|
All Other Fees (c)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
75,000
|
|
|
|
29,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,413,150
|
|
|
$
|
1,359,499
|
|
|
$
|
1,339,325
|
|
|
$
|
1,331,829
|
|
|
$
|
3,111,525
|
|
|
$
|
3,394,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Fees for audit services billed in 2006 and 2005 consisted of:
|
|
|
§
|
|
Audit of the companies financial statements.
|
|
|
|
|
§
|
|
Reviews of the companies quarterly financial statements.
|
|
|
|
|
§
|
|
Comfort letters, regulatory audits, consents and other services related to SEC matters.
|
|
(b)
|
|
Fees for audit related services billed in 2006 and 2005 consisted of:
|
|
|
§
|
|
Sarbanes-Oxley Act, Section 404 advisory services.
|
|
|
|
|
§
|
|
Agreed upon procedures.
|
|
(c)
|
|
Fees for all other services billed in 2006 and 2005 consisted of permitted non-audit
services, such as:
|
|
(d)
|
|
2005 Audit fees have been adjusted from information previously presented to
reflect fees for audit services relating to the audit of the 2005 financial statements,
including internal controls over financial reporting for SPR, billed subsequent to the
filing of the 2006 proxy statement.
|
In considering the nature of the services provided by the independent registered public
accounting firm, the Audit Committee determined that such services are compatible with the
provision of independent audit services. The Audit Committee discussed these services with the
independent auditor and management to determine that they are permitted under the rules and
regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley
Act of 2002, as well as the American Institute of Certified Public Accountants.
Pre-Approval Policy
The services performed by Deloitte and Touche LLP, in 2006 were pre-approved on February 26, 2006 meeting by
the Audit Committee in accordance with the pre-approval policy and procedures adopted by the Audit
Committee. This policy describes the permitted audit, audit-related, tax, and other services
(collectively, the “Disclosure Categories”) that Deloitte and Touche may perform. The policy
requires that prior to the beginning of each fiscal year, a description of the services (the
“Service List”) expected to be performed by Deloitte and Touche in each of the Disclosure
Categories in the following fiscal year be presented to the Audit Committee for approval.
Any requests for audit, audit related, tax, and other services not contemplated on the Service
List must be submitted to the Audit Committee for specific pre-approval and cannot commence until
such approval has been granted. Normally, pre-approval is provided at regularly scheduled
meetings. However, the authority to grant specific pre-approval between meetings, as necessary,
has been delegated to the Chairman of the Audit Committee. Under the policy, the Chairman must
update the Audit Committee at the next regularly scheduled meeting of any services that were
granted specific pre-approval.
In addition, although not required by the rules and regulations of the SEC, the Audit
Committee (generally) requests a range of fees associated with each proposed service on the Service
List and any services that were not originally included on the Service List. Providing a range of
fees for a service incorporates appropriate oversight and control of the independent auditor
relationship, while permitting the Company to receive immediate assistance from the independent
auditor when time is of the essence.
202
On a quarterly basis, the Audit Committee reviews the status of services and fees incurred
year-to-date against the original Service List and the forecast of remaining services and fees for
the fiscal year.
The policy contains a
de minimis
provision that operates to provide retroactive approval for
small immaterial and permissible non-audit services under certain circumstances. The provision
allows for the pre-approval requirement to be waived if all of the following criteria are met:
|
|
1.
|
|
The service is not an audit, review or other attest service;
|
|
|
|
|
2.
|
|
The aggregate amount of all such services provided under this provision
does not exceed the lesser of $50,000 or five percent of total fees paid to the
independent auditor in a given fiscal year;
|
|
|
|
|
3.
|
|
Such services were not recognized at the time of the engagement to be
non-audit services;
|
|
|
|
|
4.
|
|
Such services are promptly brought to the attention of the Audit
Committee and approved by the Audit Committee or its designee; and
|
|
|
|
|
5.
|
|
The service and fee are specifically disclosed in the Proxy Statement as
meeting the
de minimis
requirements.
|
During 2006, fees for audit related services, tax services and all other fees were
pre-approved by the Audit Committee or Chairman of the Audit Committee.
203
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements, Financial Statement Schedules and Exhibits
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Page
|
|
|
|
1.
|
|
|
Financial Statements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reports of Independent Registered Public Accounting Firm
|
|
|
95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sierra Pacific Resources:
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2006 and 2005
|
|
|
98
|
|
|
|
|
|
|
Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
99
|
|
|
|
|
|
|
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
100
|
|
|
|
|
|
|
Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
101
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
102
|
|
|
|
|
|
|
Consolidated Statements of Capitalization as of December 31, 2006 and 2005
|
|
|
103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nevada Power Company:
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2006 and 2005
|
|
|
105
|
|
|
|
|
|
|
Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
106
|
|
|
|
|
|
|
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
107
|
|
|
|
|
|
|
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
108
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
109
|
|
|
|
|
|
|
Consolidated Statements of Capitalization as of December 31, 2006 and 2005
|
|
|
110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sierra Pacific Power Company
:
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2006 and 2005
|
|
|
111
|
|
|
|
|
|
|
Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
112
|
|
|
|
|
|
|
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
113
|
|
|
|
|
|
|
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
114
|
|
|
|
|
|
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
|
|
|
115
|
|
|
|
|
|
|
Consolidated Statements of Capitalization as of December 31, 2006 and 2005
|
|
|
116
|
|
|
|
|
|
|
Notes to Financial Statements for Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power
Company
|
|
|
117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.
|
|
|
Financial Statement Schedules:
|
|
|
|
|
|
|
|
|
|
Schedule I
– Condensed Financial Statements of Sierra Pacific Resources
|
|
|
206
|
|
|
|
|
|
|
Schedule II – Consolidated Valuation and Qualifying Accounts
|
|
|
207
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All other schedules have been omitted because they are not required or are not applicable, or
the required information is shown in the financial statements or notes thereto. Columns omitted
from schedules have been omitted because the information is not applicable.
|
|
|
|
|
|
|
|
|
|
|
|
|
3.
|
|
|
Exhibits:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits are
listed in the Exhibit Index on pages 209 to 218.
|
|
|
|
|
204
SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934,
Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company have each duly
caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The
signatures for each undersigned company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.
|
|
|
|
|
|
|
|
SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
|
|
|
|
By
/s/ Walter M. Higgins
|
|
|
|
Walter M. Higgins
|
|
|
|
Chairman, Chief Executive Officer
and Director
|
|
|
|
February 28, 2007
|
|
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of Sierra Pacific Resources, Nevada Power Company
and Sierra Pacific Power Company and in the capacities indicated on the 28th day of February, 2007.
|
|
|
|
|
|
|
|
|
|
|
/s/
|
|
William D. Rogers
William D. Rogers
|
|
|
|
/s/
|
|
John E. Brown
John
E. Brown
|
|
|
|
Chief Financial Officer (Principal Financial Officer)
|
|
|
|
|
|
Controller (Principal Accounting Officer)
|
|
|
|
|
|
|
|
|
|
|
|
/s/
|
|
Mary Lee Coleman
Mary Lee Coleman
|
|
|
|
/s/
|
|
Jerry E. Herbst
Jerry
E. Herbst
|
|
|
|
Director
|
|
|
|
|
|
Director
|
|
|
|
|
|
|
|
|
|
|
|
/s/
|
|
Krestine M. Corbin
Krestine M. Corbin
|
|
|
|
/s/
|
|
John F. O’Reilly
John
F. O’Reilly
|
|
|
|
Director
|
|
|
|
|
|
Director
|
|
|
|
|
|
|
|
|
|
|
|
/s/
|
|
Theodore J. Day
Theodore J. Day
|
|
|
|
/s/
|
|
Clyde T. Turner
Clyde
T. Turner
|
|
|
|
Director
|
|
|
|
|
|
Director
|
|
|
|
|
|
|
|
|
|
|
|
/s/
|
|
James R. Donnelley
James R. Donnelley
|
|
|
|
/s/
|
|
Joseph B. Anderson, Jr.
Joseph
B. Anderson, Jr.
|
|
|
|
Director
|
|
|
|
|
|
Director
|
|
|
|
|
|
|
|
|
|
|
|
/s/
|
|
Philip G. Satre
Philip G. Satre
|
|
|
|
/s/
|
|
Donald D. Snyder.
Donald
D. Snyder
|
|
|
|
Director
|
|
|
|
|
|
Director
|
|
|
|
|
|
|
|
|
|
|
|
/s/
|
|
Michael W. Yackira
Michael W. Yackira
|
|
|
|
/s/
|
|
Brian J. Kennedy
Brian J. Kennedy
|
|
|
|
Director
|
|
|
|
|
|
Director
|
205
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED BALANCE SHEETS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Investments and other property, net (Note 4)
|
|
$
|
3,045,872
|
|
|
$
|
2,539,689
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
25,206
|
|
|
|
35,185
|
|
|
Accounts receivable less allowance for
uncollectible accounts:
|
|
|
|
|
|
|
|
|
|
2006-$0
|
|
|
1,755
|
|
|
|
—
|
|
|
Dividends receivable from subsidiary
|
|
|
20,208
|
|
|
|
321
|
|
|
Materials, supplies and fuel, at average cost
|
|
|
13
|
|
|
|
2
|
|
|
Deferred income taxes
|
|
|
138
|
|
|
|
—
|
|
|
Other
|
|
|
420
|
|
|
|
946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47,740
|
|
|
|
36,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Charges and Other Assets:
|
|
|
|
|
|
|
|
|
|
Goodwill (Note 18)
|
|
|
469
|
|
|
|
22,877
|
|
|
Regulatory asset for pension plans
|
|
|
2,906
|
|
|
|
—
|
|
|
Unamortized debt issuance costs
|
|
|
10,269
|
|
|
|
13,545
|
|
|
Deferred income tax benefit
|
|
|
105,010
|
|
|
|
148,451
|
|
|
Other
|
|
|
1,611
|
|
|
|
68,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120,265
|
|
|
|
253,113
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
3,213,877
|
|
|
$
|
2,829,256
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common shareholders’ equity
|
|
$
|
2,622,297
|
|
|
$
|
2,060,154
|
|
|
Long-term debt
|
|
|
550,545
|
|
|
|
661,255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,172,842
|
|
|
|
2,721,409
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
8,581
|
|
|
|
75,723
|
|
|
Accrued interest
|
|
|
12,216
|
|
|
|
14,561
|
|
|
Accrued salaries and benefits
|
|
|
2,948
|
|
|
|
2,617
|
|
|
Deferred income taxes
|
|
|
—
|
|
|
|
144
|
|
|
Accrued taxes
|
|
|
212
|
|
|
|
182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,957
|
|
|
|
93,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 13)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
Accrued retirement benefits
|
|
|
11,691
|
|
|
|
11,124
|
|
|
Other
|
|
|
5,387
|
|
|
|
3,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,078
|
|
|
|
14,620
|
|
|
|
|
|
|
|
|
|
|
TOTAL CAPITALIZATION AND LIABILITIES
|
|
$
|
3,213,877
|
|
|
$
|
2,829,256
|
|
|
|
|
|
|
|
|
|
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED INCOME STATEMENTS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of goodwill
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11,695
|
|
|
Other
|
|
|
5,952
|
|
|
|
19,006
|
|
|
|
15,114
|
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes (benefits)
|
|
|
(23,595
|
)
|
|
|
(33,078
|
)
|
|
|
(39,332
|
)
|
|
Other than income
|
|
|
172
|
|
|
|
152
|
|
|
|
132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,471
|
)
|
|
|
(13,920
|
)
|
|
|
(12,391
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
17,471
|
|
|
|
13,920
|
|
|
|
12,391
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Early debt conversion fees
|
|
|
—
|
|
|
|
(54,000
|
)
|
|
|
—
|
|
|
Subsidiary earnings
|
|
|
324,152
|
|
|
|
185,777
|
|
|
|
122,626
|
|
|
Other income
|
|
|
4,236
|
|
|
|
1,573
|
|
|
|
545
|
|
|
Other expense
|
|
|
(6,595
|
)
|
|
|
(2,627
|
)
|
|
|
(1,379
|
)
|
|
Income (taxes) / benefits
|
|
|
1,157
|
|
|
|
18,799
|
|
|
|
596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
322,950
|
|
|
|
149,522
|
|
|
|
122,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Before Interest Charges
|
|
|
340,421
|
|
|
|
163,442
|
|
|
|
134,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
51,431
|
|
|
|
74,323
|
|
|
|
88,323
|
|
|
Other
|
|
|
11,539
|
|
|
|
6,882
|
|
|
|
17,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62,970
|
|
|
|
81,205
|
|
|
|
106,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Applicable to Common Stock
|
|
$
|
277,451
|
|
|
$
|
82,237
|
|
|
$
|
28,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount per share basic and diluted — (Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Applicable to Common Stock
|
|
$
|
1.33
|
|
|
$
|
0.44
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares of Common Stock Outstanding — basic
|
|
|
208,531,134
|
|
|
|
185,548,314
|
|
|
|
183,080,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares of Common Stock Outstanding — diluted
|
|
|
209,020,896
|
|
|
|
185,932,504
|
|
|
|
183,400,303
|
|
|
|
|
|
|
|
|
|
|
|
|
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash
used by Operating Activities
|
|
|
(59,166
|
)
|
|
|
(147,993
|
)
|
|
|
(130,541
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments in subsidiaries and other property — net
|
|
|
(284,490
|
)
|
|
|
(231,182
|
)
|
|
|
(7,853
|
)
|
|
Dividends received from subsidiaries
|
|
|
161,793
|
|
|
|
65,819
|
|
|
|
57,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash used by Investing Activities
|
|
|
(122,697
|
)
|
|
|
(165,363
|
)
|
|
|
49,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in restricted cash and investments
|
|
|
—
|
|
|
|
21,677
|
|
|
|
21,652
|
|
|
Proceeds from issuance of long-term debt
|
|
|
—
|
|
|
|
220,211
|
|
|
|
335,000
|
|
|
Retirement of long-term debt
|
|
|
(110,710
|
)
|
|
|
(132,949
|
)
|
|
|
(290,883
|
)
|
|
Sale of common stock, net of issuance cost
|
|
|
282,594
|
|
|
|
236,208
|
|
|
|
3,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash from Financing Activities
|
|
|
171,884
|
|
|
|
345,147
|
|
|
|
69,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(9,979
|
)
|
|
|
31,791
|
|
|
|
(11,985
|
)
|
|
Beginning Balance in Cash and Cash Equivalents
|
|
|
35,185
|
|
|
|
3,394
|
|
|
|
15,379
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending Balance in Cash and Cash Equivalents
|
|
$
|
25,206
|
|
|
$
|
35,185
|
|
|
$
|
3,394
|
|
|
|
|
|
|
|
|
|
|
|
|
206
Sierra Pacific Resources
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2006, 2005 and 2004
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
Provision for Uncollectible Accounts
|
|
|
Balance at January 1, 2004
|
|
$
|
44,917
|
|
|
Provision charged to income
|
|
|
10,813
|
|
|
Amounts written off, less recoveries
|
|
|
(19,533
|
)
|
|
|
|
|
|
|
Balance at December 31, 2004
|
|
$
|
36,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, 2005
|
|
$
|
36,197
|
|
|
Provision charged to income
|
|
|
9,550
|
|
|
Amounts written off, less recoveries
|
|
|
(9,519
|
)
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
$
|
36,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, 2006
|
|
$
|
36,228
|
|
|
Provision charged to income
|
|
|
13,476
|
|
|
Amounts written off, less recoveries
|
|
|
(10,138
|
)
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
$
|
39,566
|
|
|
|
|
|
|
Nevada Power Company
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2006, 2005 and 2004
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
Provision for Uncollectible Accounts
|
|
|
Balance at January 1, 2004
|
|
$
|
40,297
|
|
|
Provision charged to income
|
|
|
7,794
|
|
|
Amounts written off, less recoveries
|
|
|
(17,190
|
)
|
|
|
|
|
|
|
Balance at December 31, 2004
|
|
$
|
30,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, 2005
|
|
$
|
30,901
|
|
|
Provision charged to income
|
|
|
6,966
|
|
|
Amounts written off, less recoveries
|
|
|
(7,481
|
)
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
$
|
30,386
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, 2006
|
|
$
|
30,386
|
|
|
Provision charged to income
|
|
|
10,795
|
|
|
Amounts written off, less recoveries
|
|
|
(8,347
|
)
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
$
|
32,834
|
|
|
|
|
|
|
207
Sierra Pacific Power Company
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2006, 2005 and 2004
(Dollars in Thousands)
|
|
|
|
|
|
|
|
|
Provision for Uncollectible Accounts
|
|
|
Balance at January 1, 2004
|
|
$
|
4,620
|
|
|
Provision charged to income
|
|
|
3,019
|
|
|
Amounts written off, less recoveries
|
|
|
(2,343
|
)
|
|
|
|
|
|
|
Balance at December 31, 2004
|
|
$
|
5,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, 2005
|
|
$
|
5,296
|
|
|
Provision charged to income
|
|
|
2,584
|
|
|
Amounts written off, less recoveries
|
|
|
(2,038
|
)
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
$
|
5,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, 2006
|
|
$
|
5,842
|
|
|
Provision charged to income
|
|
|
2,681
|
|
|
Amounts written off, less recoveries
|
|
|
(1,791
|
)
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
$
|
6,732
|
|
|
|
|
|
|
208
2006 FORM 10-K EXHIBIT INDEX
(a) Exhibits Index
Certain of the following exhibits with respect to SPR and its subsidiaries, Nevada Power Company,
Sierra Pacific Power Company, Lands of Sierra, Inc., Sierra Pacific Energy Company and Sierra Water
Development Company, are filed herewith. Certain other of such exhibits have heretofore been filed
with the Commission and are incorporated herein by reference.
(* filed herewith)
(3) Sierra Pacific Resources
|
|
•
|
|
Restated and Amended Articles of Incorporation of Sierra Pacific Resources, dated
May 24, 2006 (filed as Exhibit 3.1 to Form 10-Q for quarter ended June 30, 2006).
|
|
|
|
|
•
|
|
By-laws of Sierra Pacific Resources as amended through May 3, 2005 (filed as Exhibit
3.1 to Form 8-K filed May 9, 2005).
|
Nevada Power Company
|
|
•
|
|
Restated Articles of Incorporation of Nevada Power Company, dated July 28, 1999
(filed as Exhibit 3(B) to Form 10-K for year ended December 31, 1999).
|
|
|
|
|
•
|
|
Amended and Restated By-Laws of Nevada Power Company dated July 28, 1999 (filed as
Exhibit 3(C) to Form 10-K for year ended December 31, 1999).
|
Sierra Pacific Power Company
|
|
•
|
|
Restated Articles of Incorporation of Sierra Pacific Power Company dated October 25,
2006 (filed as Exhibit 3.1 to Form 10-Q for the quarter ended September 30, 2006).
|
|
|
|
|
•
|
|
By-laws of Sierra Pacific Power Company, as amended through November 13, 1996 (filed
as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1996).
|
|
|
|
|
•
|
|
Articles of Incorporation of Piñon Pine Corp., dated December 11, 1995 (filed as
Exhibit (3)(A) to Form 10-K for the year ended December 31, 1995).
|
|
|
|
|
•
|
|
Articles of Incorporation of Piñon Pine Investment Co., dated December 11, 1995
(filed as Exhibit (3)(B) to Form 10-K for the year ended December 31, 1995).
|
|
|
|
|
•
|
|
Agreement of Limited Liability Company of Piñon Pine Company, L.L.C., dated December
15, 1995, between Piñon Pine Corp., Piñon Pine Investment Co. and GPSF-B INC 1995
(filed as Exhibit (3)(C) to Form 10-K for the year ended December 31, 1995).
|
|
|
|
|
•
|
|
Amended and Restated Limited Liability Company Agreement of SPPC Funding LLC dated
as of April 9, 1999, in connection with the issuance of California rate reduction bonds
(filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1999).
|
(4) Sierra Pacific Resources
|
|
•
|
|
Indenture between Sierra Pacific Resources and The Bank of New York, dated May 1,
2000, for the issuance of debt securities (filed as Exhibit 4.1 to Form 8-K dated May
22, 2000).
|
209
|
|
•
|
|
Officers’ Certificate dated August 12, 2005, establishing the terms of Sierra
Pacific Resources’ 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.1 to Form 10-Q for
the quarter ended September 30, 2005).
|
|
|
|
|
•
|
|
Form of Sierra Pacific Resources’ 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.2
to Form 10-Q for the quarter ended September 30, 2005).
|
|
|
|
|
•
|
|
Officers’ Certificate dated June 14, 2005, establishing the terms of Sierra Pacific
Resources’ 7.803% Senior Notes due 2007 (filed as Exhibit 99.1 to Form 8-K filed June
16, 2005).
|
|
|
|
|
•
|
|
Indenture, dated March 19, 2004, between Sierra Pacific Resources and the Bank of
New York, as Trustee, in connection with the issuance of 8 5/8% Senior Notes due 2014
(filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2004).
|
|
|
|
|
•
|
|
Form of Sierra Pacific Resources’ 8 5/8% Senior Notes due 2014 (filed as Exhibit 4.1
to Form 10-Q for the quarter ended March 31, 2004).
|
Nevada Power Company
|
|
•
|
|
General and Refunding Mortgage Indenture, dated May 1, 2001, between Nevada Power
Company and The Bank of New York, as Trustee (filed as Exhibit 4.1(a) to Form 10-Q for
the quarter ended June 30, 2001).
|
|
|
|
|
•
|
|
First Supplemental Indenture, dated as of May 1, 2001, establishing Nevada Power
Company’s 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed
as Exhibit 4.1(b) to Form 10-Q for the quarter ended June 30, 2001).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Nevada Power Company’s 8.25% General
and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.l(c) to
Form 10-Q for the quarter ended June 30, 2001).
|
|
|
|
|
•
|
|
Form of Nevada Power Company’s 8.25% General and Refunding Mortgage Bonds, Series A,
due June 1, 2011 (filed as Exhibit 4.1(d) to Form 10-Q for the quarter ended June 30,
2001).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Nevada Power Company’s 9% General
and Refunding Mortgage Notes, Series G, due 2013 (filed as Exhibit 4.1 to Form 10-Q for
the quarter ended September 30, 2003).
|
|
|
|
|
•
|
|
Form of Nevada Power Company’s 9% General and Refunding Mortgage Notes, Series G,
due 2013 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2003).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Nevada Power Company’s 6 1/2%
General and Refunding Mortgage Notes, Series I, due 2012 (filed as Exhibit 4.1 to Form
10-Q for quarter ended June 30, 2004).
|
|
|
|
|
•
|
|
Form of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I
due 2012 (filed as Exhibit 4.2 to Form 10-Q for quarter ended June 30, 2004).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Nevada Power Company’s 5 7/8%
General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(A) to Form
10-K filed for year ended December 31, 2005).
|
|
|
|
|
•
|
|
Form of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series
L, due 2015 (filed as Exhibit 4(B) to Form 10-K filed for year ended December 31,
2005).
|
210
|
|
•
|
|
Officer’s Certificate establishing the terms of Nevada Power Company’s 5.95% General
and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(A) to Form 10-K
for the year ended December 31, 2005).
|
|
|
|
|
•
|
|
Form of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M,
due 2016 (filed as Exhibit 4(B) to Form 10-K for the year ended December 31, 2005).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Nevada Power Company’s 6.650%
General and Refunding Mortgage Notes, Series N, due 2036 (filed as Exhibit 4.1 to Form
10-Q for the quarter ended March 31, 2006.
|
|
|
|
|
•
|
|
Form of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series
N, due 2036 (filed as Appendix A to Exhibit 4.1 to Form 10-Q for the quarter ended
March 31, 2006).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Nevada Power Company’s 6.50% General
and Refunding Mortgage Notes, Series O, due 2018 (filed as Exhibit 4.7 to Form S-4
filed June 7, 2006).
|
|
|
|
|
•
|
|
Form of 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (included in
Exhibit 4.7) (filed as Appendix A to Exhibit 4.7 to Form S-4 filed June 7, 2006).
|
Sierra Pacific Power Company
|
|
•
|
|
General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Sierra
Pacific Power Company and The Bank of New York as Trustee (filed as Exhibit 4.2(a) to
Form 10-Q for the quarter ended June 30, 2001).
|
|
|
|
|
•
|
|
First Supplemental Indenture, dated as of May 1, 2001, establishing Sierra Pacific
Power Company’s 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008
(filed as Exhibit 4.2(b) to Form 10-Q for the quarter ended June 30, 2001).
|
|
|
|
|
•
|
|
*(A) Second Supplemental Indenture, dated as of October 30, 2006, to subject
additional properties of Sierra Pacific Power Company located in the State of
California to the lien of the General and Refunding Mortgage Indenture and to correct
defects in the original Indenture.
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 8%
General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit
4.2(c) to Form 10-Q for the quarter ended June 30, 2001).
|
|
|
|
|
•
|
|
Form of Sierra Pacific Power Company’s 8% General and Refunding Mortgage Bonds,
Series A, due June 1, 2008 (filed as Exhibit 4.2(d) to Form 10-Q for the quarter ended
June 30, 2001).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6
1/4% General and Refunding Mortgage Bonds, Series H, due 2012 (filed as Exhibit 4.4 to
Form 10-Q for the quarter ended March 31, 2004).
|
|
|
|
|
•
|
|
Form of Sierra Pacific Power Company’s 6 1/4% General and Refunding Mortgage Bonds,
Series H, due 2012 (filed as Exhibit 4.5 to Form 10-Q for the quarter ended March 31,
2004).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s
General and Refunding Mortgage Notes, Series J, due 2009 (filed as Exhibit 4(E) to Form
10-K for the year ended December 31, 2004).
|
211
|
|
•
|
|
Form of Sierra Pacific Power Company’s General and Refunding Mortgage Notes, Series
J, due 2009 (filed as Exhibit 4(F) to Form 10-K for the year ended December 31, 2004).
|
|
|
|
|
•
|
|
Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6%
General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4.4 to Form
10-Q for the quarter ended March 31, 2006).
|
|
|
|
|
•
|
|
Form of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes,
Series M, due 2016 (filed as Appendix A to Exhibit 4.4 to Form 10-Q for the quarter
ended March 31, 2006).
|
|
|
|
|
•
|
|
Indenture dated as of April 9, 1999 between SPPC Funding LLC and Bankers Trust
Company of California, N.A., in connection with the issuance of California rate
reduction bonds (filed as Exhibit 4(C) to Form 10-K for the year ended December 31,
1999).
|
|
|
|
|
•
|
|
First Series Supplement dated as of April 9, 1999 to Indenture between SPPC Funding
LLC and Bankers Trust Company of California, N.A., in connection with the issuance of
California rate reduction bonds (filed as Exhibit 4(D) to Form 10-K for year ended
December 31, 1999).
|
|
|
|
|
•
|
|
Form of SPPC Funding LLC Notes, Series 1999-1, in connection with the issuance of
California rate reduction bonds (filed as Exhibit 4(E) to Form 10-K for year ended
December 31, 1999).
|
(10) Sierra Pacific Resources
|
|
•
|
|
Employment Agreement for Walter M. Higgins (filed as Exhibit 10.1 to Form 10-Q for
the quarter ended September 30, 2003).
|
|
|
|
|
•
|
|
Amendment to Employment Agreement for Walter M. Higgins (filed as Exhibit 10.1 to
Form 10-Q for the quarter ended June 30, 2006).
|
|
|
|
|
•
|
|
Michael W. Yackira Employment Letter dated March 17, 2003 (filed as Exhibit 10(A) to
Form 10-K for the year ended December 31, 2002).
|
|
|
|
|
•
|
|
Paul J. Kaleta Employment Letter dated January 9, 2006 (filed as Exhibit 10(A) to
Form 10-K for the year ended December 31, 2005).
|
|
|
|
|
•
|
|
Stephen R. Wood Employment Letter dated June 29, 2004 (filed as Exhibit 10.1 to Form
10-Q for the quarter ended March 31, 2004).
|
|
|
|
|
•
|
|
Roberto Denis Employment Letter dated July 11, 2003 (filed as Exhibit 10(B) to Form
10-K for the year ended December 31, 2003).
|
|
|
|
|
•
|
|
Change in Control Agreement by and among Sierra Pacific Resources and the following
officers (individually): Jeffrey L. Ceccarelli, Donald L. Shalmy, Michael W. Yackira,
Roberto Denis, Stephen R. Wood and Paul J. Kaleta in substantially the same form as the
Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources
and Dennis D. Schiffel (filed as Exhibit 10(C) to Form 10-K for the year ended December
30, 2001).
|
|
|
|
|
•
|
|
Change in Control Agreement by and among Sierra Pacific Resources and the following
officers (individually): Mary O. Simmons and John E. Brown in substantially the same
form as the Change in Control Agreement dated May 21, 2001 by and between Sierra
Pacific Resources and John E. Brown (filed as Exhibit 10(D) to Form 10-K for the year
ended December 30, 2001).
|
|
|
|
|
•
|
|
Sierra Pacific Resources’ 2004 Executive Long-Term Incentive Plan (filed as Appendix
A to 2004 Proxy Statement).
|
212
|
|
•
|
|
Sierra Pacific Resources’ Non-Employee Director Stock Plan (filed as Exhibit 99.2 to
Form S-8 dated December 13, 1999).
|
|
|
|
|
•
|
|
Sierra Pacific Resources’ Employee Stock Purchase Plan (filed as Exhibit 99.3 to
Form S-8 dated December 13, 1999).
|
Nevada Power Company
|
|
•
|
|
*(A) Lease, dated December 11, 2006, between Nevada Power Company as lessee and
Beltway Business Park Warehouse No. 2, LLC as lessor, relating to Nevada Power
Company’s South Operations Center facility.
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•
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Second Amended and Restated Credit Agreement, dated as of November 4, 2005, among
Nevada Power Company, Wachovia Bank, as administrative agent, the Lenders from time to
time party thereto and the other parties named therein (filed as Exhibit 10.1 to the
Form 10-Q for the quarter ended September 30, 2005).
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•
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Amendment and Consent, dated April 19, 2006, to the Second Amended and Restated
Credit Agreement, dated November 4, 2005, among Nevada Power Company, Wachovia Bank,
National Association, as Administrative Agent, the Lenders from time to time party
thereto and the other parties named therein (filed as Exhibit 10.1 to Form 10-Q for the
quarter ended March 31, 2006).
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•
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Financing Agreement between Clark County, Nevada and Nevada Power Company, dated
August 1, 2006 (relating to Clark County, Nevada $39,500,000 Pollution Control Refund
Revenue Bonds Series 2006) (filed as Exhibit 10.1 to Form 10-Q for the quarter ended
September 30, 2006).
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•
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Financing Agreement between Coconino County, Arizona Pollution Control Corporation
and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona
$40,000,000 Pollution Control Corporation Refunding Revenue Bonds Series 2006A) (filed
as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2006).
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•
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Financing Agreement between Coconino County, Arizona Pollution Control Corporation
and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona
Pollution Control Corporation $13,000,000 Pollution Control Refunding Revenue Bonds
Series 2006B) (filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30,
2006).
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•
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Financing Agreement No. 1 between Clark County, Nevada and Nevada Power Company,
dated June 1, 2000 (Series 2000A) (filed as Exhibit 10(O) to Form 10-K for the year
ended December 31, 2000).
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•
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Financing Agreement No. 2 between Clark County, Nevada and Nevada Power Company,
dated June 1, 2000 (Series 2000B) (filed as Exhibit 10(P) to Form 10-K for the year
ended December 31, 2000).
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•
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Financing Agreement between Clark County, Nevada and Nevada Power Company, dated
November 1, 1997 (relating to Clark County, Nevada $52,285,000 Industrial Development
Revenue Bonds, Series 1997A) (filed as Exhibit 10.83 to Form 10-K, File No. 1-4698, for
the year ended December 31, 1997).
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•
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Financing Agreement between Clark County, Nevada and Nevada Power Company dated
October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development
Revenue Bonds, Series 1995A) (filed as Exhibit 10.75 to Form 10-K, File No. 1-4698, for
the year ended December 31, 1995).
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213
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•
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Financing Agreement between Clark County, Nevada and Nevada Power Company dated
October 1, 1995 (relating to Clark County, Nevada $85,000,000 Industrial Development
Refunding Revenue Bonds, Series 1995B) (filed as Exhibit 10.76 to Form 10-K, File No.
1-4698, for the year ended December 31, 1995).
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•
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Financing Agreement between Clark County, Nevada and Nevada Power Company dated
October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development
Revenue Bonds, Series 1995A and $44,000,000 Industrial Development Refunding Revenue
Bonds, Series 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-1698, for the
year ended December 31, 1995).
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•
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Financing Agreement between Clark County, Nevada and Nevada Power Company dated
October 1, 1995 (relating to Clark County, Nevada $20,300,000 Pollution Control
Refunding Revenue Bonds, Series 1995D) (filed as Exhibit 10.78 to Form 10-K, File No.
1-4698, for the year ended December 31, 1995).
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•
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Financing Agreement between Clark County, Nevada and Nevada Power Company dated
October 1, 1992 (Relating to Industrial Development Refunding Revenue Bonds, Series
1992C) (filed as Exhibit 10.67 to Form 10-K, File No. 1-4698, for the year ended
December 31, 1992).
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•
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Financing Agreement between Clark County, Nevada and Nevada Power Company dated June
1, 1992 (Relating to Clark County, Nevada $105,000,000 Industrial Development Revenue
Bonds, Series 1992A) (filed as Exhibit 10.65 to Form 10-K, File No. 1-4698, for the
year ended December 31, 1992).
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•
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Collective Bargaining Agreement dated as of February 1, 2005, effective through
February 1, 2008, between Nevada Power Company and the International Brotherhood of
Electrical Workers Local Union No. 396 (filed as Exhibit 10.1 to Form 10-Q for the
quarter ended March 31, 2005).
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•
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Engineering, Procurement and Construction Agreement dated October 13, 2004 between
Nevada Power Company and Fluor Enterprises, Inc. and Exhibit A thereto (filed as
Exhibit 10.3 and Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004).
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•
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Contract for Sale of Electrical Energy between the State of Nevada and Nevada Power
Company, dated July 8, 1987 (filed as Exhibit 10.39 to Form 10-K, File No. 1-4698, for
the year ended December 31, 1987).
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•
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Participation Agreement Reid Gardner Unit No. 4 dated July 11, 1979 between Nevada
Power Company and California Department of Water Resources (filed as Exhibit 5.34 to
Form S-7, File No. 2-65097).
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•
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Amended Mohave Project Coal Slurry Pipeline Agreement dated May 26, 1976 between
Peabody Coal Company and Black Mesa Pipeline, Inc. (Exhibit B to Exhibit 10.18) (filed
as Exhibit 5.36 to Form S-7, File No. 2-56356).
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•
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Amended Mohave Project Coal Supply Agreement dated May 26, 1976 between Nevada Power
Company and Southern California Edison Company, Department of Water and Power of the
City of Los Angeles, Salt River Project Agricultural Improvement and Power District and
the Peabody Coal Company (filed as Exhibit 5.35 to Porto S-7, File No. 2-56356).
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•
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Navajo Project Co-Tenancy Agreement dated March 23, 1976 between Nevada Power
Company, Arizona Public Service Company, Department of Water and Power of the City of
Los Angeles, Salt River Project Agricultural Improvement and Power District, Tucson Gas
& Electric Company and the United States of America (filed as Exhibit 5.31 to Form 8-K,
File No. 1-4696, April 1974).
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214
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•
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Mohave Operating Agreement dated July 6, 1970 between Nevada Power Company, Salt
River Project Agricultural Improvement and Power District, Southern California Edison
Company and Department of Water and Power of the City of Los Angeles (filed as Exhibit
13.26F to Form S-1, File No. 2-38314).
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•
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Navajo Project Coal Supply Agreement dated June 1, 1970 between Nevada Power
Company, the United States of America, Arizona Public Service Company, Department of
Water and Power of the City of Los Angeles, Salt River Project Agricultural District
Tucson Gas & Electric Company and the Peabody Coal Company (filed as Exhibit 13.27B to
Form S-1, File No. 2-38314).
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•
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Eldorado System Conveyance and Co-Tenancy Agreement dated December 20, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.30 to Form S-9, File No. 2-28348).
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•
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Mohave Project Plant Site Conveyance and Co-Tenancy Agreement dated May 29, 1967
between Nevada Power Company and Salt River Project Agricultural Improvement and Power
District and Southern California Edison Company (filed as Exhibit 13.27 to Form S-9,
File No. 2-28348).
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•
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Settlement Agreement dated December 19, 2003, between Nevada Power Company, Pinnacle West Energy Corporation and Southern Nevada Water Authority (filed as Exhibit 10(G) to the Form 10-K for the year ended December 31, 2003).
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•
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Sublease Agreement between Powveg Leasing Corp., as Lessor and Nevada Power Company
as lessee, dated January 1, 1984 for lease of administrative headquarters (the primary
term of the sublease ends in 2014 and the lessee has the option to extend the term up
to 25 additional years) (filed as Exhibit 10.31 to Form 10-K, File No. 1-4698, for the
year ended December 31, 1983).
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Sierra Pacific Power Company
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•
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Amended and Restated Credit Agreement, dated as of November 4, 2005 among Sierra
Pacific Power Company, Wachovia Bank, National Association, as administrative agent,
the Lenders from time to time party thereto and the other parties named therein (filed
as Exhibit 10.2 to the Form 10-Q for the quarter ended September 30, 2005).
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•
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Amendment and Consent, dated April 19, 2006, to the Amended and Restated Credit
Agreement, dated November 4, 2005, among Sierra Pacific Power Company, Wachovia Bank,
National Association, as Administrative Agent, the Lenders from time to time party
thereto and the other parties named therein (filed as Exhibit 10.2 to Form 10-Q for the
quarter ended March 31, 2006).
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•
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*(B) Financing Agreement dated November 1, 2006 between Humboldt County, Nevada and
Sierra Pacific Power Company dated November 1, 2006 (relating to Humboldt County,
Nevada $49,750,000 Pollution Control Refunding Revenue Bonds (Sierra Pacific Power
Company Project) Series 2006).
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•
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*(C) Financing Agreement dated November 1, 2006 between Washoe County, Nevada and
Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada
$58,750,000 Gas Facilities Control Refunding Revenue Bonds (Sierra Pacific Power
Company Project) Series 2006A).
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•
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*(D) Financing Agreement dated November 1, 2006 between Washoe County, Nevada and
Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada
$75,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power
Company Project) Series 2006B).
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•
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*(E) Financing Agreement dated November 1, 2006 between Washoe County, Nevada and
Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada
$84,800,000 Gas and Water Facilities Control Refunding Revenue Bonds (Sierra Pacific
Power Company Project) Series 2006C).
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•
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Financing Agreement dated as of March 1, 2001 between Sierra Pacific Power Company
and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities
Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2001 (filed as
Exhibit 10(O) to Form 10-K for the year ended December 31, 2001).
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215
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•
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Transition Property Purchase and Sale Agreement dated as of April 9, 1999 between
Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of
California rate reduction bonds (filed as Exhibit 10(B) to Form 10-K for the year ended
December 31, 1999).
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•
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Transition Property Servicing Agreement dated as of April 9, 1999 between Sierra
Pacific Power Company and SPPC Funding LLC in connection with the issuance of
California rate reduction bonds (filed as Exhibit 10(C) to Form 10-K for the year ended
December 31, 1999).
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•
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Administrative Services Agreement dated as of April 9, 1999 between Sierra Pacific
Power Company and SPPC Funding LLC in connection with the issuance of California rate
reduction bonds (filed as Exhibit 10(D) b Form 10-K for the year ended December 31,
1999).
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•
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Collective Bargaining Agreement dated January 1, 2003, effective through December
31, 2005 between Sierra Pacific Power Company and the International Brotherhood of
Electrical Workers Local No. 1245 (filed as Exhibit 10(J) to the Form 10-K for the year
ended December 31, 2003).
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•
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Settlement Agreement and Mutual Release dated May 8, 1992 between Sierra Pacific
Power Company and Coastal States Energy Company (filed as Exhibit (10)(D) to Form 10-K
for the year ended December 31, 1992; confidential portions omitted and filed
separately with the Securities and Exchange Commission).
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•
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Coal Supply Agreement dated January 1, 2002 between Sierra Pacific Power Company and
Arch Coal Sales Company, Inc. (5 year term ending on December 31, 2006) (filed as
Exhibit 10(R) to Form 10-K for the year ended December 31, 2001).
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•
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Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and
Coastal States Energy Company (confidential portions omitted and flied separately with
lie Securities and Exchange Commission) (filed as Exhibit 5-GG to Registration No.
2-62476).
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•
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Amendment No. 1 dated November 8, 1983 to Coal Sales Agreement dated May 16, 1978
between Sierra Pacific Power Company and Coastal States Energy Company (filed as
Exhibit(10)(B) to Form 10-K for the year ended December 31, 1991).
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•
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Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement dated May 16, 1978
between Sierra Pacific Power Company and Coastal Stores Energy Company (filed as
Exhibit (10)(A) to Form 10-K for the year ended December 31, 1993).
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•
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Amendment No. 3 dated May 8, 1992 to Coal Sales Agreement dated May 16, 1978 between
Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10(B)
to Form 10-K for the year ended December 31, 1992; confidential portions omitted and
filed separately with the Securities and Exchange Commission).
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•
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Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman
Associates Limited Partnership relating to the Company’s corporate headquarters
building (filed as Exhibit(10)(I) to Form 10-K for the year ended December 31, 1992).
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•
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Letter of Amendment dated May 18, 1987 to Lease dated January 30, 1986 between
Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to
the company’s corporate headquarters building (filed as Exhibit (10)(K) to Form 10-K
for the year ended December 31, 1993).
|
216
Sierra Pacific Communications
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•
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Unit Redemption, Release, and Sale Agreement entered into by and among Touch
America, Inc., Sierra Pacific Communications, and Sierra Touch America LLC, dated as of
September 9, 2002 (filed as Exhibit 10.4 to Form 10-Q for the quarter ended September
30, 2002).
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•
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Amended and Restated Conduit Sale Agreement dated September 11, 2002, made by and
between Sierra Pacific Communications and Quest Communications Corporation (filed as
Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2002).
|
(11) Nevada Power Company and Sierra Pacific Power Company
|
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•
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Nevada Power Company and Sierra Pacific Power Company are wholly owned subsidiaries
and, in accordance with Paragraph 6 of SFAS No. 128 (Earnings Per Share), earnings per
share data have been omitted.
|
(12) Sierra Pacific Resources
|
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•
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*(A) Statement regarding computation of Ratios of Earnings to Fixed Charges.
|
Nevada Power Company
|
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•
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*(B) Statement regarding computation of Ratios of Earnings to Fixed Charges.
|
Sierra Pacific Power Company
|
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•
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*(C) Statement regarding computation of Ratios of Earnings to Fixed Charges.
|
(21) Sierra Pacific Resources
|
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•
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Nevada Power Company, a Nevada Corporation.
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Sierra Pacific Power Company, a Nevada Corporation.
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Great Basin Energy Company, a Nevada Corporation.
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Lands of Sierra Inc., a Nevada Corporation.
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Sierra Energy Company dba e-three, a Nevada Corporation.
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Sierra Gas Holdings Company, a Nevada Corporation.
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Sierra Pacific Energy Company, a Nevada Corporation.
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Sierra Water Development Company, a Nevada Corporation.
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Tuscarora Gas Pipeline Company, a Nevada Corporation.
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Tuscarora Gas Operating Company, a Nevada Corporation.
|
Nevada Power Company
|
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•
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Nevada Electric Investment Company, a Nevada Corporation.
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Commonsite, Inc., a Nevada Corporation.
|
Sierra Pacific Power Company
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•
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Piñon Pine Company, a Nevada Corporation.
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Piñon Pine Investment Company, a Nevada Corporation.
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Piñon Pine Investment Co. LLC, a Nevada Limited Liability Company.
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GPSF-B, a Delaware Corporation.
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SPPC Funding LLC, a Delaware Limited Liability Company.
|
217
(23) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company
|
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•
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*(A) Consent of Independent Registered Public Accounting Firm in connection with
Sierra Pacific Resources’ Registration Statements No. 333-77523 (Common Stock
Investment Plan) on Form S-3, No. 333-92651 (Employees’ Stock Ownership Plan, Executive
Long-Term Incentive Plan, and Non-Employee Director Stock Plan) on Form S-8, No.
333-72160 (Post-Effective Amendment to Registration) on Form S-3/A and Registration Statement No.
333-135752 (automatic shelf registration statement of securities of well-known seasoned
issuers) on Form S-3.
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•
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|
*(B) Consent of Independent Registered Public Accounting Firm in connection
with Nevada Power Company’s Registration Statement on Form S-3, No. 333-130189 (shelf
registration statement).
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•
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|
*(C) Consent of Independent Registered Public Accounting Firm in
connection with Sierra Pacific Power Company’s Registration Statement on Form S-3, No.
333-130191 (shelf registration statement).
|
(31) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company
|
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•
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*(31.1) Annual Certification of Chief Executive Officer of Sierra Pacific Resources
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
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•
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*(31.2) Annual Certification of Chief Executive Officer of Nevada Power Company
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
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•
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*(31.3) Annual Certification of Chief Executive Officer of Sierra Pacific Power
Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
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•
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*(31.4) Annual Certification of Chief Financial Officer of Sierra Pacific Resources
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
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•
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|
*(31.5) Annual Certification of Chief Financial Officer of Nevada Power Company
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
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•
|
|
*(31.6) Annual Certification of Chief Financial Officer of Sierra Pacific Power
Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
(32) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company
|
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•
|
|
*(32.1) Certification of Chief Executive Officer of Sierra Pacific Resources
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
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•
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*(32.2) Certification of Chief Executive Officer of Nevada Power Company Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
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•
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|
*(32.3) Certification of Chief Executive Officer of Sierra Pacific Power Company
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
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•
|
|
*(32.4) Certification of Chief Financial Officer of Sierra Pacific Resources
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
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•
|
|
*(32.5) Certification of Chief Financial Officer of Nevada Power Company Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
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•
|
|
*(32.6) Certification of Chief Financial Officer of Sierra Pacific Power Company
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
218
Exhibit 4(A)
SIERRA PACIFIC POWER COMPANY
TO
THE BANK OF NEW YORK
Trustee
SECOND SUPPLEMENTAL INDENTURE
Dated as of October 30, 2006
SUPPLEMENTING AND AMENDING THE GENERAL AND REFUNDING MORTGAGE INDENTURE
DATED AS OF MAY 1, 2001
THIS INSTRUMENT GRANTS A SECURITY INTEREST BY A PUBLIC UTILITY
THIS INSTRUMENT CONTAINS AFTER-ACQUIRED PROPERTY PROVISIONS
THIS INSTRUMENT IS BEING FILED IN THE STATE OF NEVADA PURSUANT TO NEVADA REVISED
STATUTES CHAPTER 105 AND IN THE STATE OF CALIFORNIA.
SECOND SUPPLEMENTAL INDENTURE, dated as of October 30, 2006 (herein
called the "SECOND SUPPLEMENTAL INDENTURE"), between SIERRA PACIFIC POWER
COMPANY, a corporation duly organized and existing under the laws of the State
of Nevada (herein called the "COMPANY"), having its principal office at 6100
Neil Road, Reno, Nevada 89520-0040, and THE BANK OF NEW YORK, a New York banking
corporation duly organized and existing under the laws of the State of New York,
as trustee (herein called the "TRUSTEE") the office of the Trustee at which on
the date hereof its corporate trust business is principally administered being
101 Barclay Street, New York, New York 10286.
Each capitalized term that is used herein and not otherwise defined
herein and which is defined in the Original Indenture referred to hereinafter
shall have the meaning specified in the Original Indenture.
RECITALS
WHEREAS, the Company has heretofore executed and delivered to the
Trustee a General and Refunding Mortgage, dated as of May 1, 2001 (the "Original
Indenture"), providing for the issuance by the Company from time to time of its
bonds, notes or other evidence of indebtedness to be issued in one or more
series (in the Indenture and herein called the "Securities") and to provide
security for the payment of the principal of and premium, if any, and interest,
if any, on the Securities; and
WHEREAS, the Company has heretofore executed and delivered to the
Trustee a First Supplemental Indenture, dated as of May 1, 2001; and
WHEREAS, Section 14.01 of the Original Indenture provides, among other
things, that, without the consent of any Holders, the Company and the Trustee
may enter into indentures supplemental to the Indenture, for the purposes, among
others, of (a) subjecting to the Lien of the Indenture additional properties of
the Company, (b) correcting any provision in the Indenture which may be
defective or inconsistent with any other provision in the Indenture, and (c)
making additions or changes to the provisions under the Indenture which
additions and changes shall not adversely affect the interests of the Holders of
any Outstanding Securities or Tranche in any material respect; and
WHEREAS, the Company has executed this Second Supplemental Indenture
and has requested the Trustee to join in this Second Supplemental Indenture for
the purpose of (a) subjecting to the Lien of the Indenture additional properties
of the Company located in the State of California, and (b) correcting defects in
Sections 1.01, 1.02(a) and 4.03(a) of the Original Indenture; and
WHEREAS, all things necessary to make this Second Supplemental
Indenture a valid, binding and legal agreement of the Company have been done,
and all conditions necessary to authorize the execution, delivery and recording
of this Second Supplemental Indenture have been complied with or have been done
or performed;
PART I: GRANTING CLAUSES
NOW, THEREFORE, THIS SECOND SUPPLEMENTAL INDENTURE WITNESSETH, that, in
consideration of the premises and of the purchase of the Securities by the
1
Holders thereof, and in order to secure the payment of the principal of and
premium, if any, and interest, if any, on all Securities now and hereafter from
time to time Outstanding and the performance of the covenants therein and
contained in the Indenture and to declare the terms and conditions on which such
Securities are secured, the Company hereby grants, bargains, sells, conveys,
assigns, transfers, mortgages, pledges, sets over and confirms to the Trustee
and to The Bank of New York Trust Company, N.A., a national banking association
organized and existing under the laws of the United States of America, as
co-trustee under the Indenture (the "Co-Trustee), appointed as such pursuant to
the Instrument of Appointment and Acceptance hereinafter referred to, and grants
to the Trustee and the Co-Trustee, as joint tenants and not tenants in common, a
security interest in the following (subject, however, to the terms and
conditions set forth in the Indenture and the Instrument of Appointment and
Acceptance hereinafter referred to):
GRANTING CLAUSE FIRST
All right, title and interest of the Company, as of the date of the
execution and delivery of this Second Supplemental Indenture, in and to
all property, real, personal and mixed, located in the State of
California (other than Excepted Property), including without limitation
all right, title and interest of the Company in and to the following
property so located (other than Excepted Property): (a) all real
property owned in fee, easements and other interests in real property
which are specifically described or referred to in Exhibit A attached
hereto and incorporated herein by this reference; (b) all licenses,
permits to use the real property of others, franchises to use public
roads, streets and other public properties, rights of way and other
rights or interests relating to the occupancy or use of real property,
including without limitation all of the same which are specifically
described or referred to in Exhibit B attached hereto and incorporated
herein by this reference; (c) all facilities, machinery, equipment and
fixtures for the generation, transmission and distribution of electric
energy including, but not limited to, all plants, powerhouses, dams,
diversion works, generators, turbines, engines, boilers, fuel handling
and transportation facilities, air and water pollution control and
sewage and solid waste disposal facilities, switchyards, towers,
substations, transformers, poles, lines, cables, conduits, ducts,
conductors, meters, regulators and all other property used or to be
used for any or all of such purposes; (d) all facilities, machinery,
equipment and fixtures for the transmission, storage and distribution
of gas including, but not limited to, gas works, stations and
substations, transmission pipelines, storage facilities, holders,
tanks, retorts, purifiers, odorizers, scrubbers, compressors, valves,
regulators, pumps, mains, pipes, service pipes, conduits, ducts,
fittings and connections, services, meters and any and all other
property used or to be used for any or all of such purposes; (e) all
buildings, offices, warehouses, structures or improvements in addition
to those referred to or otherwise included in clauses (a), (c) and (d)
above; (f) all computers, data processing, data storage, data
transmission and/or telecommunications facilities, equipment and
apparatus necessary for the operation or maintenance of any facilities,
machinery, equipment or fixtures described or referred to in clauses
(c) or (d) above; and (g) all of the foregoing property in the process
of construction;
2
GRANTING CLAUSE SECOND
Subject to the applicable exceptions permitted by Section 8.09(c),
Section 13.03 and Section 13.05 of the Original Indenture, all right,
title and interest of the Company in all property, real, personal and
mixed, located in the State of California (other than Excepted
Property) which may be hereafter acquired by the Company, it being the
intention of the Company that all such property acquired by the Company
after the date of the execution and delivery of this Second
Supplemental Indenture, shall be as fully embraced within and subjected
to the Lien of the Indenture as if such property were owned by the
Company as of the date of the execution and delivery of this Second
Supplemental Indenture; and
GRANTING CLAUSE THIRD
All tenements, hereditaments, servitudes and appurtenances belonging or
in any wise appertaining to the aforesaid property, with the reversions
and remainders thereof;
PROPERTIES EXCEPTED
There are, however, expressly excepted and excluded from the Lien of
the Indenture (a) all property of the character excepted or excluded or
intended to be excepted or excluded under the definition of "Excepted
Property" in the Original Indenture, subject to the proviso at the end
of the "Excepted Property" clause in the Original Indenture, and (b)
all property set forth in Exhibit D attached hereto.
TO HAVE AND TO HOLD all such property, real, personal and mixed, unto
the Trustee and the Co-Trustee, their successors in trust and their assigns
forever;
SUBJECT, HOWEVER, to (a) Liens existing at the date of the execution
and delivery of this Second Supplemental Indenture, (including, but not limited
to, the Lien of the SPPC 1940 Mortgage, as defined below), (b) as to property
acquired by the Company after the date of the execution and delivery of this
Second Supplemental Indenture, Liens existing or placed thereon at the time of
the acquisition thereof (including, but not limited to, Purchase Money Liens),
(c) Permitted Liens and all other Liens permitted to exist under Section 6.06 of
the Indenture; and
SUBJECT, FURTHER, to the condition that, with respect to any property
which is now or hereafter becomes subject to the Lien of the SPPC 1940 Mortgage,
the Lien of this Second Supplemental Indenture shall at all times be junior,
subject and subordinate to the Lien of the SPPC 1940 Mortgage;
IN TRUST, NEVERTHELESS, for the equal and ratable benefit and security
of the Holders from time to time of all Outstanding Securities without any
priority of any such Security over any other such Security; and
PROVIDED, HOWEVER, that the right, title and interest of the Trustee
and the Co-Trustee in and to the Mortgaged Property shall cease, terminate and
become void in accordance with, and subject to the conditions set forth in,
Article IX or Article XIV of the Indenture, and if, thereafter, the principal of
and premium, if any, and interest, if any, on the Securities shall have been
paid to the
3
Holders thereof, or shall have been paid to the Company pursuant to
Section 6.03 of the Indenture, then and in that case the Indenture shall
terminate, and the Trustee and, to the extent necessary, the Co-Trustee, shall
execute and deliver to the Company such instruments as the Company shall require
to evidence such termination; otherwise the Indenture and the estate and rights
hereby granted, shall be and remain in full force and effect.
PART II: AMENDMENTS TO THE INDENTURE
The Original Indenture is hereby amended, as permitted by Section
14.01(j) of the Original Indenture, as follows:
Section 2.01 Amendments to General Definitions.
(a) The definition of "EXPERT'S CERTIFICATE" in
Section 1.01 of the Original Indenture is hereby amended by deleting
the reference to Section "4.03" therein and inserting a reference to
Section "4.02" in its place and by deleting the reference to
Section "7.07" therein.
(b) The definition of "SPPC 1940 MORTGAGE" in
Section 1.01 of the Original Indenture is hereby amended by deleting it
in its entirety and replacing it with the following:
"SPPC 1940 Mortgage" means the Indenture of
Mortgage, dated as of December 1, 1940, from Sierra Pacific
Power Company (the Company, successor) to The New England
Trust Company (U.S. Bank National Association, successor) and
Leo W. Huegle (Gerald R. Wheeler, successor), trustees, as
heretofore and hereafter amended and supplemented.
Section 2.02 Amendment to Funded Property Definition. Clause (a) of
Section 1.02 of the Original Indenture is hereby amended by deleting it in its
entirety and inserting the following new clause (a) in its place:
"(a) all Property Additions to the extent that the same
shall have been designated in the Initial Expert's Certificate to be
deemed to be Funded Property;"
Section 2.03 Amendment to Issuance of Securities on the Basis of
Retired Securities. Clause (a) of Section 4.03 of the Original Indenture is
hereby amended by deleting the words "Subject to the provisions of
subsection (c) of this Section," located at the beginning of such clause.
PART III: MISCELLANEOUS PROVISIONS
Section 3.01 The Company and the Trustee, acting pursuant to the
provisions of Section 11.14 of the Indenture, do hereby appoint said The Bank
of New York Trust Company, N.A., as co-trustee under the Indenture with respect
to Mortgaged Property located in the State of California and
4
the Lien granted by this Second Supplemental Indenture, such appointment
acknowledged by and subject to the terms of the Instrument of Appointment and
Acceptance executed by the Company, the Trustee and the Co-Trustee, dated as of
the date of this Second Supplemental Indenture, an original executed counterpart
of which is attached hereto as Exhibit E.
Section 3.02 Any moneys received by the Trustee as proceeds of any
title insurance policy on Mortgaged Property (or, in the case of the Co-Trustee,
any proceeds of any title insurance policy on Mortgaged Property located in the
State of California) of the Company shall be subject to and treated in
accordance with the provisions of Section 6.07(b) of the Indenture (other than
the last paragraph thereof).
Section 3.03 The Trustee makes no undertaking or representations in
respect of, and shall not be responsible in any manner whatsoever for and in
respect of, the validity or sufficiency of this Second Supplemental Indenture or
the proper authorization or the due execution hereof by the Company or for or in
respect of the recitals and statements contained herein, all of which recitals
and statements are made solely by the Company.
Section 3.04 Except as expressly amended and supplemented hereby, the
Indenture shall continue in full force and effect in accordance with the
provisions thereof and the Indenture is in all respects hereby ratified and
confirmed. This Second Supplemental Indenture and all of its provisions shall be
deemed a part of the Indenture in the manner and to the extent herein and
therein provided.
Section 3.05 For purposes of clarification, as permitted by Section
14.01(j) of the Original Indenture, it is understood and acknowledged that: (a)
the definition of "Excepted Property" under the Indenture includes the Excepted
Property set forth in both the Original Indenture and this Second Supplemental
Indenture; and (b) all property released from the Lien of the Indenture under
Article VIII of the Original Indenture shall no longer be subject to the Lien of
the Indenture, until such time, if any, as such property shall have been
reacquired by the Company after having been sold or otherwise disposed of by the
Company.
Section 3.06 This Second Supplemental Indenture shall be governed by
and construed in accordance with, the law of the State of New York (including
without limitation Section 5-1401 of the New York General Obligations Law or any
successor to such statute), except to the extent that the Trust Indenture Act
shall be applicable and except to the extent that the law of any jurisdiction
wherein any portion of the Mortgaged Property referenced herein is located shall
mandatorily govern the creation of a mortgage lien on and security interest in,
or perfection, priority or enforcement of the Lien of this Second Supplemental
Indenture or exercise of remedies with respect to, such portion of the Mortgaged
Property.
Section 3.07 This Second Supplemental Indenture may be executed in any
number of counterparts, each of which so executed shall be deemed to be an
original, but all such counterparts shall together constitute but one and the
same instrument.
5
IN WITNESS WHEREOF, the parties hereto have caused this Second
Supplemental Indenture to be duly executed as of the day and year first above
written.
[SEAL] SIERRA PACIFIC POWER COMPANY
By:
-----------------------------------
Name: Michael W. Yackira
Title: Executive Vice President and
Chief Financial Officer
|
THE BANK OF NEW YORK, as Trustee
By:
-----------------------------------
Name: Stacey B. Poindexter
Title: Assistant Vice President
|
Exhibit 10(A)
LEASE
BELTWAY BUSINESS PARK WAREHOUSE NO. 2, LLC,
A NEVADA LIMITED LIABILITY COMPANY,
AS LANDLORD,
AND
NEVADA POWER COMPANY,
A NEVADA CORPORATION,
AS TENANT
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
TABLE OF CONTENTS
PAGE
ARTICLE ONE BASIC TERMS....................................................................... 1
ARTICLE TWO LEASE TERM........................................................................ 4
ARTICLE THREE BASE RENT......................................................................... 7
ARTICLE FOUR OTHER CHARGES PAYABLE BY TENANT................................................... 8
ARTICLE FIVE USE OF PROPERTY................................................................... 16
ARTICLE SIX CONDITION OF PROPERTY; MAINTENANCE, REPAIRS AND ALTERATIONS....................... 23
ARTICLE SEVEN DAMAGE OR DESTRUCTION............................................................. 26
ARTICLE EIGHT CONDEMNATION...................................................................... 28
ARTICLE NINE ASSIGNMENT AND SUBLETTING......................................................... 28
ARTICLE TEN DEFAULTS; REMEDIES................................................................ 32
ARTICLE ELEVEN PROTECTION OF LENDERS............................................................. 34
ARTICLE TWELVE LEGAL COSTS....................................................................... 35
ARTICLE THIRTEEN BROKERS........................................................................... 36
ARTICLE FOURTEEN BUILDING SHELL AND TENANT IMPROVEMENTS............................................ 36
ARTICLE FIFTEEN TELECOMMUNICATIONS SERVICES....................................................... 40
ARTICLE SIXTEEN MISCELLANEOUS PROVISIONS.......................................................... 40
ARTICLE SEVENTEEN MASTER LEASE...................................................................... 44
ARTICLE EIGHTEEN DECLARATION OF COVENANTS, CONDITIONS, RESTRICTIONS AND RECIPROCAL EASEMENTS....... 46
ARTICLE NINETEEN NO OPTION OR OFFER................................................................ 46
ARTICLE TWENTY CONDITION SUBSEQUENT.............................................................. 46
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EXHIBITS
A DEPICTION OR DESCRIPTION OF THE PROPERTY
B SUBORDINATION, NON-DISTURBANCE AND ATTORNMENT AGREEMENT [CONSTRUCTION
LENDER]
B-1 SUBORDINATION, NON-DISTURBANCE AND ATTORNMENT AGREEMENT [PERMANENT LENDER]
C ESTOPPEL CERTIFICATE
D HAZARDOUS MATERIALS
E CONFIRMATION OF INITIAL LEASE TERM AND AMENDMENT TO LEASE
F MEMORANDUM OF LEASE
G MASTER LEASE
H BASE BUILDING SHELL PLANS
I MODIFIED BUILDING SHELL PLANS
J TENANT'S LIMITED RESTORATION OBLIGATION
K FORM OF TENANT IMPROVEMENT CONTRACT
L MASTER LANDLORD RNDA
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
|
i
INDEX OF DEFINED TERMS
TERM PAGE
ADDITIONAL LAND......................................................... 2
ADDITIONAL RENT......................................................... 8
APPLICABLE LAWS......................................................... 16
ARCHITECT............................................................... 27
BASE BUILDING SHELL IMPROVEMENTS........................................ 37
BASE BUILDING SHELL PLANS............................................... 36
BASE RENT............................................................... 3
BROKERS................................................................. 36
BUILDING................................................................ 2
BUILDING SHELL IMPROVEMENTS............................................. 36
CAM SERVICES LIST....................................................... 15
CHANGE ORDER............................................................ 38
CHANGES................................................................. 38
COMMON AREA COSTS....................................................... 14
COMMON AREAS............................................................ 13
CONDEMNATION............................................................ 28
CONSENT................................................................. 30
CONSTRUCTION DRAWINGS................................................... 37
CONSULTANT.............................................................. 20
CONTROL................................................................. 30
COUNTY.................................................................. 44, 45
DECLARATION............................................................. 46
ENVIRONMENTAL DAMAGES................................................... 17
ENVIRONMENTAL REQUIREMENTS.............................................. 17
ESTIMATED LEASE COMMENCEMENT DATE....................................... 2
ESTIMATED SUBSTANTIAL COMPLETION DATE................................... 2
EVENT OF DEFAULT........................................................ 32
EXTENSIONS.............................................................. 5
FAIR RENTAL VALUE....................................................... 7
FINAL PLANS............................................................. 37
FORCE MAJEURE........................................................... 42
GOVERNMENTAL AGENCY..................................................... 18
HAZARDOUS MATERIAL...................................................... 16
IMPOSITION.............................................................. 25
LANDLORD................................................................ 1, 22, 41
LANDLORD'S CONTRACTOR................................................... 25
LANDLORD'S NOTICE....................................................... 37
LEASE COMMENCEMENT DATE................................................. 4
LEASE EXPIRATION DATE................................................... 4
LEASE MEMORANDUM........................................................ 42
LEASE MONTH............................................................. 7
LEASE TERM.............................................................. 4
LEASE YEAR.............................................................. 8
LEASEHOLD TITLE POLICY.................................................. 45
MASTER LANDLORD......................................................... 44, 45
MASTER LEASE............................................................ 44
MODIFIED BUILDING SHELL COSTS........................................... 39
NOTICE AND ACKNOWLEDGEMENT.............................................. 24
NOTICES................................................................. 41
NRS..................................................................... 8
OFAC.................................................................... 43, 44
OPTIONS................................................................. 5
PERMITTED PURCHASER..................................................... 30
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7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
ii
PERMITTED USES............................................................. 2
POSTED SECURITY REQUIREMENTS............................................... 24
PRO RATA SHARE............................................................. 14
PROJECT.................................................................... 2
PROPERTY................................................................... 2
REAL PROPERTY TAX.......................................................... 8
RECORDS.................................................................... 38
REDETERMINATION REQUEST.................................................... 7
RENT....................................................................... 8
RENTAL ADJUSTMENT DATE..................................................... 7
RENTAL ADJUSTMENT DATES.................................................... 6
RESTORATION................................................................ 27
SIGN....................................................................... 21
STRUCTURAL AND SAFETY ALTERATIONS.......................................... 25, 26
SUBJECT SPACE.............................................................. 28
SUBLEASE................................................................... 30
SUBTENANT.................................................................. 30
TAX CONTEST................................................................ 9
TELECOMMUNICATIONS EQUIPMENT............................................... 40
TENANT..................................................................... 1, 22
TENANT AFFILIATE........................................................... 30
TENANT GROUP............................................................... 18
TENANT IMPROVEMENTS........................................................ 37
TENANT'S ALTERATIONS....................................................... 24
TENANT'S COSTS............................................................. 38
TENANT'S OBJECTION......................................................... 37
TENANT'S REQUEST AND ACCEPTANCE NOTICE..................................... 38
TENANT'S SHARE............................................................. 39
TENANT'S TELECOMMUNICATIONS EQUIPMENT...................................... 40
TERMINATION OPTION......................................................... 46
TRANSFER NOTICE............................................................ 28
TRANSFER PREMIUM........................................................... 29
TRANSFEREE................................................................. 28
TRANSFERS.................................................................. 28
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7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
iii
LEASE
ARTICLE ONE BASIC TERMS
This Article One contains the Basic Terms of this Lease between Landlord
and Tenant named below. Other Articles, Sections and Paragraphs of this Lease
referred to in this Article One explain and define the Basic Terms and are to be
read in conjunction with the Basic Terms.
Section 1.01. DATE OF LEASE: December 11, 2006.
Section 1.02. LANDLORD: BELTWAY BUSINESS PARK WAREHOUSE NO. 2, LLC, a
Nevada limited liability company.
Address of Landlord: c/o Majestic Realty Co.
13191 Crossroads Parkway North, Sixth Floor
City of Industry, California 91746
Attention: Property Management
[Telephone: (562) 692-9581]
[Fax: (562) 695-0441]
With a copy of any notices to:
c/o Majestic Realty Co.
4155 W. Russell Road, Suite C
Las Vegas, Nevada 89118
Attention: Property Manager
[Telephone: (702) 896-5564]
[Fax: (702) 896-4838]
|
MASTER LANDLORD: (see Article Seventeen) County of Clark, a
political subdivision of the State of Nevada.
Section 1.03. TENANT: NEVADA POWER COMPANY, a Nevada corporation.
Address of Tenant: Nevada Power Company
Administrative Services
6226 W. Sahara Ave.
Las Vegas, Nevada 89146
Attention: Director of Administrative Services
[Telephone: (702) 367-5636]
[Fax: (702) 367-5095]
With copies of any notices to:
Nevada Power Company
Legal Department
6226 W. Sahara Ave.
Las Vegas, Nevada 89146
Attention: General Counsel
[Telephone: (702) 367-5000]
[Fax: (702) 227-2069]
and:
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
|
1
K. Michael Leavitt
Leavitt, Sully & Rivers
601 E. Bridger Ave.
Las Vegas, NV 89101
[Fax: (702) 382-2892]
Section 1.04. PROPERTY: The Property (defined below) is part of Landlord's
multi-tenant real property development which will, when completed, consist of
two (2) buildings having a total of approximately 540,000 square feet of
rentable space and described or depicted on the attached Exhibit "A" (the
"PROJECT"). The Project includes the land, the buildings and all other
improvements located on the land, and the Common Areas and Common Area
Improvements (as defined in Section 4.05(a) below). The property that is the
subject of this Lease is that part of the Project known as Building 5 (which
will include approximately 288,000 square feet of space) (the "BUILDING"), the
real property upon which the Building and certain Common Areas are located
("BUILDING PREMISES") consisting of approximately 16.00 acres of land generally
located at 7155 Lindell Road, Las Vegas, Nevada, plus approximately 15.94 acres
of land adjacent to the Building Premises (the "ADDITIONAL LAND"), all as shown
on 4 7155 Lindell Road Las Vegas, Nevada Nevada Power Company DMWEST #6375379
v25 Exhibit "A" attached hereto (collectively, the "PROPERTY"). Although some
Common Area Improvements will be physically located on the Building Premises, as
used in this Lease, neither the defined term "Building" nor the defined term
"Property" is intended to include those improvements included within the defined
term "Common Area Improvements," unless otherwise expressly provided. The square
footage figures for the Project and the Property, as recited in this Section
1.04, are approximate. No adjustment will be made to the Base Rent or any other
amounts payable by Tenant under this Lease (or to any other provisions of this
Lease) if the actual square footage, however measured, is more or less than the
square footage recited.
Section 1.05. TERM.
(a) LEASE TERM: Twenty (20) years, subject to Sections 2.05 and
3.01, commencing on the Lease Commencement Date.
(b) LEASE COMMENCEMENT DATE: The Lease Commencement Date (as defined
in Section 2.01 below) of the initial Lease Term shall be the one hundred
eightieth (180th) day following Substantial Completion (as defined in Article
Fourteen below) of the Building Shell Improvements (as defined in Article
Fourteen below). The estimated date of Substantial Completion of the Building
Shell Improvements is February 1, 2007 (the "ESTIMATED SUBSTANTIAL COMPLETION
DATE"), and the Lease Commencement Date is estimated to be August 1, 2007 (the
"ESTIMATED LEASE COMMENCEMENT DATE"). Upon determination of the actual date of
Substantial Completion of the Building Shell Improvements and the actual Lease
Commencement Date, Landlord and Tenant shall promptly execute a Confirmation of
Initial Lease Term and Amendment to Lease, substantially in the form of that
attached as Exhibit "E" to this Lease.
(c) LEASE EXPIRATION DATE: Subject to Section 2.05, the expiration
date of the initial Lease Term shall be the last day of the two hundred fortieth
(240th) calendar month following the month in which the Lease Commencement Date
falls, unless the Lease Commencement Date is the first day of a calendar month,
in which event the expiration date shall be the last day of the two hundred
thirty-ninth (239th) calendar month following the month in which the Lease
Commencement date falls.
Section 1.06. PERMITTED USES: Office uses; employee fitness center;
storage, warehousing and distribution uses, including, but not limited to
storage and distribution of transformers; design and engineering uses; employee
training; fabrication, assembly and manufacture of items, parts, equipment and
apparatus for use by Tenant, its affiliates and/or permitted Subtenants (as
defined in Section 9.08) in the course of their business, but not for sale to
third parties except with the prior written consent of Landlord; communication,
telecommunication and technological activities and services; call center; credit
union office and services; food and drink preparation, service and sale (but not
for commercial purposes with the general public), including cafeteria and
concession sales; cleaning, maintenance, repair and restoration of personal
property, including equipment and apparatus (but not for commercial purposes
with the public or third parties except with the prior written consent of
Landlord); parking, storage, cleaning, fueling, maintenance, repair and
restoration of vehicles (but not for commercial purposes with the public or
third parties except with the prior written consent of Landlord, and with such
uses to be conducted primarily on the Additional Land); demonstration energy
conservation projects, including solar panels and wind
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
2
turbines; public meeting rooms for community organizations; uses reasonably
related to all of the foregoing; and any other uses approved in advance, in
writing, by Landlord. Consistent with the above, if in the course of consenting
to a proposed assignment or subletting requiring Landlord's consent under
Article Nine below, Landlord expressly approves a different use of all or a
portion of the Property, then such different use (and any ancillary office use)
shall also constitute a Permitted Use under this Lease. Subject to any
restrictions and requirements of Applicable Laws (as defined in Section 5.02
below). Tenant's outside storage yard on the westerly portion of the Additional
Land shall have block walls on the north, west and south boundaries. Any
permanent outside storage of items on other portions of the Property shall be
screened from view from adjacent public roadways, as may be reasonably required
by Landlord. Notwithstanding any language to the contrary in this Section 1.06,
no such Permitted Use shall (i) create obnoxious (as to a reasonable person)
odors or noise, (ii) include storage of tire or other products made with like
materials (except for storage of tires on the Additional Land for future use on
vehicles of Tenant and permitted Subtenants, and temporary storage of used tires
on the Additional Land preceding offsite disposition), (iii) include storage of
explosives, or (iv) involve fabrication or manufacturing, except as specifically
allowed above in this Section 1.06.
Section 1.07. SECURITY DEPOSIT: None.
Section 1.08. TENANT'S GUARANTOR: None.
Section 1.09. BROKERS: (See Article Thirteen)
Landlord's Broker: Majestic Realty Co.
4155 W. Russell Road, Suite C
Las Vegas, Nevada 89118
and
Valley Realty, LLC
7181 Amigo Street, Suite 100
Las Vegas, Nevada 89119
Tenant's Broker: Commerce CRG of Nevada, LLC
3930 Howard Hughes Parkway, Suite 250
Las Vegas, Nevada 89109
|
Section 1.10. RENT AND OTHER CHARGES PAYABLE BY TENANT: (Subject to the
provisions of Section 3.01).
(a) BASE RENT:
Lease Term Monthly Installment of Base Rent
---------- --------------------------------
Partial calendar month (if any) $250,000.00 (prorated)
at commencement of Lease Term
Lease Months 1 through 3 $125,000.00
Lease Months 4 through 24 $250,000.00
Lease Months 25 through 48 $265,000.00
Lease Months 49 through 72 $280,900.00
Lease Months 73 through 96 $297,754.00
Lease Months 97 through 120 $315,619.24
Lease Months 121 through 144 $334,556.39
Lease Months 145 through 168 $354,629.78
Lease Months 169 through 192 $375,907.56
Lease Months 193 through 216 $398,462.02
Lease Months 217 through 240 $422,369.74
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
|
3
(b) OTHER PERIODIC PAYMENTS: (i) Real Property Taxes (see Section
4.02 below); (ii) Utilities (see Section 4.03 below); and (iii) Tenant's Pro
Rata Share--which shall be fifty percent (50%)--of Common Area Costs (see
Section 4.05(e) below).
ARTICLE TWO LEASE TERM
Section 2.01. LEASE OF PROPERTY FOR LEASE TERM. The term of this Lease
(the "LEASE TERM") shall be as set forth in Section 1.05(a) above, shall
commence on the date (the "LEASE COMMENCEMENT DATE") set forth in Section
1.05(b) above, and shall terminate on the date (the "LEASE EXPIRATION DATE") set
forth in Section 1.05(c) above, unless sooner terminated or extended as
expressly provided in this Lease. The terms and provisions of this Lease shall
be effective as of the date of this Lease, except for Section 1.10, Article
Three (save and except Section 3.03), Article Four (save and except for Section
4.04(a) with respect to, but only with respect to, acts and omissions of Tenant,
its agents, employees, contractors or other persons under the supervision and
control of Tenant while on or about the Property), Section 5.02, Section 5.03
(save and except for Section 5.03.11), Section 5.05.1, Section 6.04 and Article
Seven. Those excepted terms and provisions of this Lease not becoming effective
as of the date of this Lease shall be and become effective on the Lease
Commencement Date unless they become effective earlier pursuant to the
provisions of Section 2.03 below.
Section 2.02. DELAY IN COMMENCEMENT. Landlord shall not be liable to
Tenant if Landlord does not deliver possession of the Property to Tenant on the
Estimated Substantial Completion Date. Landlord's non-delivery of the Property
to Tenant on that date shall not affect this Lease or the obligations of Tenant
under this Lease, except that the Lease Commencement Date shall be delayed until
the one hundred eightieth (180th) day following Substantial Completion of the
Building Shell Improvements (unless such delay in Substantial Completion of the
Building Shell Improvements is the result of a Tenant Delay, as defined in
Section 14.02 below, in which event the 180-day period shall be reduced for a
period equal to the period of Tenant Delay). If Substantial Completion of the
Building Shell Improvements does not occur within one hundred eighty (180) days
following the Estimated Substantial Completion Date (extended for any periods of
Tenant Delay and any Force Majeure Delay as defined in Section 16.12 below),
Tenant may elect to cancel and terminate this Lease by giving written notice to
Landlord within fifteen (15) business days after the one hundred eighty
(180)-day period (as it may have been extended) ends. If Tenant gives such
notice, this Lease shall be canceled and terminated, and neither Landlord nor
Tenant shall have any further obligations to the other, excepting only those
obligations which have accrued prior to or which expressly survive termination
of this Lease. If Tenant fails to timely give such notice, the right to cancel
and terminate this Lease shall expire, and the Lease Term shall commence on the
one hundred eightieth (180th) day following Substantial Completion of the
Building Shell Improvements. Consistent with the terms of Section 1.05(b) above,
upon determination of the date of Substantial Completion of the Building Shell
Improvements and the Lease Commencement Date, Landlord and Tenant shall promptly
execute an amendment to this Lease setting forth the Lease Commencement Date and
Lease Expiration Date, substantially in the form attached as Exhibit "E" to this
Lease. Failure to execute such amendment shall not affect the actual Lease
Commencement Date and Lease Expiration Date. The failure of Tenant to take
possession of or to occupy the Property shall not serve to relieve Tenant of any
obligations arising on the Lease Commencement Date, and shall not delay the
payment of rent by Tenant.
Section 2.03. EARLY ENTRY AND OCCUPANCY. Prior to Substantial Completion
of the Building Shell Improvements, Tenant shall have the right of early
occupancy of the Additional Land, subject to (a) full execution of this Lease,
(b) Landlord's receipt of the sum of One Hundred Twenty-five Thousand Dollars
($125,000.00) for Base Rent for Lease Month 1, (c) Landlord's and Tenant's
receipt of any necessary governmental permits, approvals, certificates, or
consents, (d) Landlord's prior receipt of Tenant's proposed schedule describing
the timing and purposes of Tenant's early occupancy, and (e) all of the terms
and conditions of this Lease then becoming effective, with the exception of
Section 1.10, Article Three (save and except Section 3.03), Article Four (save
and except for Section 4.04(a) with respect to, but only with respect to, acts
and omissions of Tenant, its agent, employees, contractors or other persons
under the supervision and control of Tenant while on or about the Property),
Section 5.02, Section 5.03 (save and except for Section 5.03.11 and except with
respect to acts and omissions of Tenant, its agents, employees, contractors or
other parties under the supervision and control of Tenant while on or about the
Property), Section 5.05.1 (except with respect to acts and omissions of Tenant,
its agents, employees, contractors or other parties under the supervision and
control of Tenant while on or about the Property), Section 6.04 and Article
Seven. Those excepted terms and provisions of this Lease not becoming effective
for purposes of the above early
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entry and occupancy period shall be and become effective on the Lease
Commencement Date. In addition to early occupancy of the Additional Land, Tenant
and Tenant's architects and other design representatives shall have the right
during the course of construction of the Building Shell Improvements to enter
upon the Building Premises for review and inspection purposes.
Landlord and Tenant shall together review Tenant's proposed schedule describing
the timing and purposes of Tenant's early occupancy, and Landlord and Tenant
shall work in good faith with each other to limit interference with each other's
activities during any period of early occupancy. Such early occupancy shall be
for the purpose of preparing the Property for use by Tenant and any permitted
Subtenants, including the construction of the Tenant Improvements (defined in
Article Fourteen below), if Tenant elects to do so pursuant to Section 14.04
below, and the installation of improvements and equipment and storage of
inventory and other personal property of Tenant and any permitted Subtenants.
During such period, Tenant shall assume all risk of loss to Tenant's equipment,
products, and other personal property. Tenant's entry upon the Building Premises
during this period shall not interfere with construction of the Building Shell
Improvements by Landlord's contractor, and in the event it does so interfere,
Tenant shall cease all such activity on the Building Premises until Substantial
Completion of the Building Shell Improvements.
Section 2.04. HOLDING OVER. If Tenant holds over after the expiration of
the Lease Term, with or without the express or implied consent of Landlord, such
tenancy shall be from month-to-month only, and shall not constitute a renewal
hereof or an extension for any further term, and in such case Base Rent shall be
payable at a monthly rate equal to one hundred twenty percent (120%) of the Base
Rent applicable immediately before the expiration of the Lease Term. Such
month-to-month tenancy shall be subject to every other term, covenant and
agreement contained herein. Nothing contained in this Section 2.04 shall be
construed as consent by Landlord to any holding over by Tenant, and Landlord
expressly reserves the right to require Tenant to surrender possession of the
Property to Landlord as provided in this Lease upon the expiration or other
termination of this Lease. The provisions of this Section 2.04 shall not be
deemed to limit or constitute a waiver of any other rights or remedies of
Landlord provided herein or at law. If Tenant fails to surrender the Property
upon the termination or expiration of this Lease, in addition to any other
liabilities to Landlord accruing therefrom, Tenant shall protect, defend,
indemnify and hold Landlord harmless from all loss, costs (including reasonable
attorneys' fees) and liability resulting from such failure, including without
limiting the generality of the foregoing, any claims made by any succeeding
tenant founded upon such failure to surrender, and any lost profits to Landlord
resulting therefrom; provided, however, that notwithstanding the foregoing
provisions of this sentence and any language to the contrary in this Section
2.04, Tenant shall not be obligated with respect to the foregoing provisions of
this sentence and shall not be liable for any consequential damages unless (i)
Landlord enters into a written lease with a third-party, unrelated, and
unaffiliated tenant requiring delivery of the Property upon or following the
Lease Expiration Date, (ii) Landlord gives Tenant written notice of having
entered into that lease and a copy of the lease language requiring delivery of
the Property and the required date of delivery and (iii) Tenant fails to
surrender the Property by the later to occur of (a) the Lease Expiration Date or
(b) the one hundred eightieth (180th) day following Tenant's receipt of that
written notice.
Section 2.05. OPTIONS TO EXTEND LEASE TERM.
(a) Grant of Options. Landlord hereby grants to Tenant three (3)
options (the "OPTIONS") to extend the Lease Term for additional periods of ten
(10) years each (the "EXTENSIONS"), on the same terms and conditions as set
forth in this Lease, but at Base Rent as set forth below and without any
additional Options other than those granted in this Section 2.05; provided,
however, that the final Extension shall expire on the earlier of ten (10) years
following the commencement date of such Extension or the expiration date (as it
may be extended) of the Master Lease (defined below). In the event of the
exercise of one or more Options by Tenant, the Lease Expiration Date shall be
the last day of the last Extension for which the Option is exercised. Each
Option shall be exercised only by written notice delivered to Landlord not less
than two hundred seventy (270) days before the expiration of the initial Lease
Term or the preceding Extension of the Lease Term, respectively, and shall be
subject to the provisions of Section 2.05 (c)(1)(iv) below. If Tenant fails to
deliver Landlord written notice of the exercise of an Option within the
prescribed time period, such Option and any succeeding Options shall lapse, and
there shall be no further right to extend the Lease Term. Each Option shall be
exercisable by Tenant on the express conditions that at the time of the exercise
(and at all times following such exercise and prior to the commencement of the
Extension), Tenant shall not be in material default under any of the provisions
of this Lease (beyond any applicable notice and
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cure period). Following Tenant's timely and valid exercise of an Option and the
determination of the amount of Base Rent to be paid on the applicable FRV Rental
Adjustment Date (as defined below) (taking into consideration the provisions of
Section 2.05 (d)(1)(iv) below), Landlord shall prepare and Tenant shall execute
and deliver to Landlord an amendment to this Lease confirming the term of the
Extension and the amount of Base Rent payable by Tenant during such Extension.
(b) Time of Essence. Time is of the essence with respect to Tenant's
exercise of the Option(s) granted in this Section 2.05.
(c) Calculation of Rent. The Base Rent during the Extension(s) shall
be determined by a combination of the following methods:
Fair Rental Value Adjustment (Section 2.05(c)(1), below); and
Fixed Adjustment (Section 2.05(c)(2), below).
(1) Fair Rental Value Adjustment. The Base Rent shall be adjusted on
the first day of the first month of each Extension of the Lease Term (the "FRV
RENTAL ADJUSTMENT DATES") to the "fair rental value" of (a) the Base Building
Shell Improvements (as defined in Section 14.01) upon and including the Building
Premises (exclusive of any (i) Common Area Improvements, other than those
included in the Base Building Shell Plans and located on the Building Premises
[but expressly excluding the ESFR System]), and (ii) any other onsite or offsite
improvements located thereon or associated therewith, other than those included
in the Base Building Shell Plans [as defined in Section 14.01]), and (b) the
land comprising the Additional Land (as if vacant, and without any buildings,
other structures or onsite or offsite improvements located thereon or associated
therewith) (collectively, the "APPRAISED PREMISES"), determined in the manner
that follows. The fair rental value of the Appraised Premises shall equal the
Base Rent on the applicable FRV Rental Adjustment Date and shall be the sum
total of (a) of the fair rental value of the Base Building Shell Improvements
upon and including the Building Premises, as if the Building Shell Improvements
were comprised solely and exclusively of the Base Building Shell Improvements
and had been constructed upon the Building Premises on the Building Shell
Substantial Completion Date as reflected in the Base Building Shell Plans,
without any of the Building Modifications (as defined in Section 14.01),
exclusive of any (i) Common Area Improvements, other than those included in the
Base Building Shell Plans and located on the Building Premises (but expressly
excluding the ESFR System), and (ii) any other onsite or offsite improvements
located thereon or associated therewith, other than those included in the Base
Building Shell Plans, and (b) the fair rental value of the land comprising the
Additional Land, as if vacant land, without any buildings, other structures or
onsite or offsite improvements located thereon or associated therewith, all
appraised in accordance with the provisions of Section 2.05(c)(1)(iii) below.
(i) Not later than two hundred fifty (250) days prior to any
applicable FRV Rental Adjustment Date, Landlord and Tenant shall meet in an
effort to negotiate, in good faith, the fair rental value of the Appraised
Premises as of such FRV Rental Adjustment Date. If Landlord and Tenant have not
agreed upon the fair rental value of the Appraised Premises at least one hundred
eighty (180) days prior to the applicable FRV Rental Adjustment Date, the fair
rental value shall be determined by appraisal issued by a real estate appraisal
firm of national standing in the manner that follows.
(ii) If Landlord and Tenant are not able to agree upon the
fair rental value of the Appraised Premises within the prescribed time period,
then Landlord and Tenant shall attempt to agree in good faith upon a single
appraiser, not later than one hundred fifty (150) days prior to the applicable
FRV Rental Adjustment Date. If Landlord and Tenant are unable to agree upon a
single appraiser within such time period, then Landlord and Tenant shall each
appoint one appraiser not later than one hundred twenty (120) days prior to the
applicable FRV Rental Adjustment Date. Within thirty (30) days thereafter, the
two appointed appraisers shall appoint a third appraiser. If either Landlord or
Tenant fails to appoint its appraiser within the prescribed time period, the
single appraiser appointed shall determine the fair rental value of the
Appraised Premises. If both parties fail to appoint appraisers within the
prescribed time periods, then the first appraiser thereafter selected by a party
shall determine the fair rental value of the Appraised Premises. Each party
shall bear the cost of its own appraiser, and the parties shall share equally
the cost of the single or third appraiser, if applicable. The appraisers used
shall have at least five (5) years' experience in appraising
commercial/industrial real property in Clark County, Nevada. All such appraisers
shall be Members of the Appraisal Institute. The appraisers shall be instructed
to separately determine
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the fair rental value of each of the two components of the Appraised Premises as
noted and described in the second sentence of the first paragraph of this
Section 2.05(c)(1) above
(iii) For the purposes of such appraisal, the term "fair
rental value" shall mean the price that a ready and willing tenant would pay, as
of the applicable FRV Rental Adjustment Date, as monthly rent to a ready and
willing landlord of the Appraised Premises (subject to usual adjustments) if
such property were exposed for lease on the open market for a reasonable period
of time for warehouse distribution purposes as respects the Base Building Shell
Improvements and the Building Premises, and for outside storage and vehicle
parking purposes as respects the Additional Land. If a single appraiser is
chosen, then such appraiser shall determine the fair rental value of the
Appraised Premises. If two appraisers shall agree upon the fair rental value of
the Appraised Premises, then the amount so agreed upon shall be the fair rental
value of the Appraised Premises. Otherwise, the fair rental value of the
Appraised Premises shall be the amount of the appraisal which is neither the
highest nor the lowest value. Base Rent shall not be reduced pursuant to the
provisions of this Section 2.05 (c)(1)(iii) by reason of such determination of
fair rental value of the Appraised Premises. Landlord and Tenant shall instruct
the appraiser(s) to complete their determination of the fair rental value not
later than sixty (60) days prior to the applicable FRV Rental Adjustment Date.
When the fair rental value of the Appraised Premises is determined by appraisal
as provided above, Landlord shall deliver notice thereof to Tenant, together
with statement setting forth the amount of Base Rent determined therefrom. If
the fair rental value is not determined prior to the applicable FRV Rental
Adjustment Date, then Tenant shall continue to pay to Landlord the Base Rent
immediately prior to such Extension, until the fair rental value is determined.
Tenant shall pay to Landlord, within ten (10) days after receipt of Landlord's
notice, any difference between the Base Rent actually paid by Tenant to Landlord
and the new Base Rent determined hereunder.
(iv) Notwithstanding any other provision herein to the
contrary, within one hundred twenty (120) days following receipt by Tenant from
Landlord of the determination of the fair rental value and the amount of the
Base Rent determined therefrom, Tenant may give Landlord written request for
redetermination of the amount of the Base Rent ("REDETERMINATION REQUEST"). The
Redetermination Request may be for purposes of reducing the Base Rent from the
amount payable prior to the applicable FRV Rental Adjustment Date. Within thirty
(30) days following Landlord's receipt of the Redetermination Request, Landlord
and Tenant shall meet and negotiate in good faith to agree upon a redetermined
amount of Base Rent to be paid commencing on the applicable FRV Rental
Adjustment Date. If Landlord and Tenant agree to an adjustment, the adjusted
amount shall be the amount of Base Rent for the applicable period, and Tenant
shall receive credit for any overpayments. If Landlord and Tenant are unable to
agree in writing upon an adjusted amount of Base Rent within ninety (90) days of
Landlord's receipt of the Redetermination Request, Tenant shall have the right
to terminate this Lease and Tenant's further rights and obligations under this
Lease as of a date certain (the "EARLY TERMINATION DATE"), which date shall be
not less than two (2) years following Landlord's receipt of written notice from
Tenant that Tenant intends to terminate this Lease in accordance with the
foregoing provisions. The Base Rent payable by Tenant to Landlord on and after
the applicable FRV Rental Adjustment Date shall be one hundred six percent
(106%) of the Base Rent payable immediately prior to the applicable FRV Rental
Adjustment Date. If the Early Termination Date is more than two (2) years
following the applicable FRV Rental Adjustment Date, the Base Rent shall be
increased by a like amount (106% of the Base Rent then payable) every two (2)
years thereafter.
(2) Fixed Adjustment. The Base Rent shall be increased to the
following amounts on the following dates: on the first day of the 25th, 49th,
73rd and 97th months of each Extension (each a "RENTAL ADJUSTMENT DATE") by a
factor of six percent (6%) over the Base Rent payable immediately prior to the
applicable Rental Adjustment Date.
ARTICLE THREE BASE RENT
Section 3.01. TIME AND MANNER OF PAYMENT. Upon execution of this Lease,
Tenant shall pay Landlord the sum of One Hundred Twenty-five Dollars
($125,000.00) as and for the Base Rent for Lease Month 1. On the first day of
Lease Month 3, Tenant shall pay Landlord the monthly Base Rent for any partial
Lease Month at the beginning of the Lease Term. On the first day of Lease Month
2 and each month during the Lease Term thereafter, Tenant shall pay Landlord the
monthly Base Rent set forth in Section 1.10(a) above, in advance, without
offset, deduction or prior demand except as otherwise provided herein. The Base
Rent shall be payable at Landlord's address or at such other place as Landlord
may designate in writing. The term "LEASE MONTH" shall
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mean each consecutive full calendar month during the Lease Term (excluding any
partial calendar month at the inception of the Lease Term). For purposes of this
Lease, the term "LEASE YEAR" shall mean, with respect to the first Lease Year,
the period commencing on the Lease Commencement Date and ending on the last day
of the twelfth (12th) calendar month following the month in which the Lease
Commencement Date falls (unless the Lease Commencement Date falls on the first
day of a calendar month, in which case the first Lease Year will end on the last
day of the twelfth (12th) Lease Month), and with respect to subsequent Lease
Years, each consecutive twelve (12) month period during the Lease Term following
the first Lease Year. If the Lease Commencement Date is a day other than the
first day of a calendar month, then (a) the Lease Term shall include the number
of months stated (or the number of months included within the number of years
stated) in Section 1.05 above, plus the partial calendar month in which the
Lease Commencement Date falls, (b) Base Rent of $250,000.00 and Additional Rent
for such partial month shall be prorated based on the number of days in such
calendar month and (c) such rent shall be payable on the first day of Lease
Month 3.
Section 3.02. APPLICATION OF PAYMENTS. Unless otherwise agreed by Landlord
and Tenant, all payments received by Landlord from Tenant shall be applied to
the oldest payment obligation owed by Tenant to Landlord. No designation by
Tenant, either in a separate writing or on a check or money order, shall modify
this Section or have any force or effect.
Section 3.03. TERMINATION; ADVANCE PAYMENTS. Upon termination of this
Lease under Article Seven (Damage or Destruction) of this Lease, or under
Article Eight (Condemnation) of this Lease, or any other termination not
resulting from Tenant's default, and after Tenant has vacated the Property in
the manner required by this Lease, Landlord shall refund or credit to Tenant (or
Tenant's successor) any Rent, including Additional Rent, or other advance
payments made by Tenant to Landlord, and any amounts paid for Real Property
Taxes and insurance which apply to any time periods after termination of this
Lease.
ARTICLE FOUR OTHER CHARGES PAYABLE BY TENANT
Section 4.01. ADDITIONAL RENT. All charges payable by Tenant during the
Lease Term other than Base Rent are called "ADDITIONAL RENT." Unless this Lease
provides otherwise, Tenant shall pay all Additional Rent then due with the next
monthly installment of Base Rent. The term "rent" or "RENT" shall mean Base Rent
and Additional Rent. Without limitation on other obligations of Tenant that
shall survive the expiration or earlier termination of the Lease Term, the
obligations of Tenant to pay the Additional Rent provided for in this Article
Four shall survive the expiration or earlier termination of the Lease Term. The
failure of Landlord to timely furnish Tenant the amount of the Additional Rent
shall not preclude Landlord from enforcing its rights to collect such Additional
Rent after furnishing the amount.
Section 4.02. PROPERTY TAXES.
(a) REAL PROPERTY TAXES. Tenant shall pay all Real Property Taxes on
the Property (including any fees, taxes or assessments against, or as a result
of, any tenant improvements installed on the Property by or for the benefit of
Tenant) during the Lease Term. Until the Property is separately assessed as
provided in Section 4.02(c) below, Landlord shall bill Tenant in advance for
Tenant's share of the Real Property Taxes, and Tenant shall pay Landlord the
amount of such Real Property Taxes quarterly prior to their due date, as
Additional Rent. Landlord shall pay such taxes prior to such delinquency date,
provided that Tenant has timely made such payments to Landlord. Any penalty
caused by Tenant's failure to timely make such payments shall also be Additional
Rent owed by Tenant immediately upon demand. When the Property is separately
assessed as provided in Section 4.02(c) below, Tenant shall pay all Real
Property Taxes as part of Tenant's central tax assessment, or as otherwise
required by the applicable taxing authorities.
(b) DEFINITION OF "REAL PROPERTY TAX." "Real Property Tax" means ad
valorem real property tax assessed against the Property and levied pursuant to
the provisions of Nevada Revised Statutes ("NRS") 361.445-361.470, or any
successor statute, and (i) any fee, license fee, license tax, business license
fee, commercial rental tax, levy, charge, assessment, penalty or tax imposed by
any taxing authority against the Property; (ii) any tax on the Landlord's right
to receive, or the receipt of, rent or income from the Property or against
Landlord's business of leasing the Property; (iii) any tax or charge for fire
protection, streets, sidewalks, road maintenance, refuse or other services
provided to the Property by any governmental agency; (iv) any tax imposed upon
this transaction or
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based upon a re-assessment of the Property due to a change of ownership, as
defined by applicable law, or other transfer of all or part of Landlord's
interest in the Property; and (v) any charge or fee replacing any tax previously
included within the definition of Real Property Tax. "Real Property Tax" does
not, however, include (i) Landlord's federal or state income, franchise,
inheritance or estate taxes, or (ii) penalties imposed by any taxing authority
against the Property due to Landlord's failure to pay such taxes prior to
delinquency, unless such failure was due to Tenant's failure to timely make such
payments to Landlord.
(c) JOINT ASSESSMENT; TENANT'S SHARE. Until the Property is
separately assessed, Landlord shall reasonably determine Tenant's share of the
Real Property Taxes payable by Tenant under Section 4.02(a) above from the
assessor's worksheets or other reasonably available information. As used in this
Section 4.02, the Real Property Taxes for the Property shall be (i) Tenant's Pro
Rata Share of the Real Property Taxes for the Project exclusive of the
Additional Land, plus (ii) all of the Real Property Taxes for the Additional
Land. Landlord shall diligently pursue the separate assessment of the Property
as follows: Upon recordation of the Lease Memorandum (defined in Section 16.08
below), Landlord, at Landlord's cost and expense, shall have all of the Property
included in one or more Assessor's Parcels comprised exclusively of all or
portions of the Property, so that the entirety of the Property may be taxed
separately as part of Tenant's central tax assessment. The Building Premises
shall independently comprise a single Assessor's Parcel. The Additional Land
shall separately comprise one or more Assessor's Parcels of such size and
configuration as Tenant shall direct, subject to such requirements as may be
imposed by the Clark County Assessor's Office; provided, however, that the cost
of preparing any additional required legal descriptions of the Additional Land
(other than the legal description of the Additional Land attached as part of
Exhibit "A" to this Lease) due to Tenant's desire to divide the Additional Land
into multiple parcels shall be at Tenant's sole cost. Landlord shall make all
commercially reasonable, good faith efforts to have the foregoing accomplished
through Clark County administrative procedures. However, if the foregoing can be
accomplished only through division of land procedures under NRS 278.320 through
278.4725, Tenant shall reimburse to Landlord one-half (1/2) of the out-of-pocket
survey and engineering costs incurred with unaffiliated survey and engineering
firms and paid by Landlord to effect the land division. Tenant shall make such
reimbursement within thirty (30) days following the recording of applicable maps
and certificates and receipt by Tenant from Landlord of copies of the paid
invoices for such engineering and survey work. In connection with the
above-described separate assessment of the Property, Landlord and Tenant shall
execute and deliver such further instruments and perform such additional acts as
may be reasonably required to obtain the desired central tax assessment
treatment.
(d) PERSONAL PROPERTY TAXES.
(i) Tenant shall pay all taxes charged against trade fixtures,
furnishings, equipment or any other personal property belonging to Tenant.
Tenant shall diligently pursue the separate assessment of such personal
property, so that it is taxed separately from the Property.
(ii) If any of Tenant's personal property is taxed with the
Property and the Property is not separately assessed, Tenant shall pay Landlord
the taxes for the personal property with its payment to Landlord of Real
Property Taxes.
(e) CONTEST OF TAXES. Tenant, at Tenant's sole cost and expense,
shall have the right, in Landlord's name, if appropriate, to contest Real
Property Taxes on the Property by appropriate legal or administrative
proceedings (a "TAX CONTEST"), subject to the terms of this Section 4.02(e). In
such event, Tenant may defer payment of the contested tax but shall promptly pay
such contested tax or cause it to be paid under protest prior to such time as
the Property may be subject to conveyance by the Clark County Treasurer pursuant
to the provisions of NRS 361.595, 361.603 or NRS 361.604, as those provisions
may, from time to time, be amended. If there shall be any refund with respect to
any contested tax based on a payment by Tenant, Tenant shall be entitled to the
same to the extent of such payment. If the Property is not taxed separate and
apart from other portions of the Project, Landlord shall have the right to
participate jointly with Tenant in any contest of Real Property Taxes relative
to any portion of the Property not so separately taxed. In such event, Landlord
shall bear all costs incurred by Landlord relative to such participation.
Landlord shall promptly cooperate with Tenant, execute such documents and take
such actions as may be reasonably necessary to enable Tenant to properly contest
any tax contemplated in this section; provided, however, that Landlord shall not
be required to incur any out-of-pocket costs in connection with the same except
to the extent that Landlord elects to do so if Landlord elects to proceed
jointly with Tenant relative to the contest of such tax as provided in the
foregoing provisions of this Section 4.02(e). Tenant shall and
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hereby agrees to indemnify, defend and hold harmless Landlord of, from and
against any and all costs, liabilities or tax obligations (including without
limitation any increases in taxes) resulting from any such contest in which
Landlord does not jointly participate with Tenant as provided in the foregoing
provisions of this Section 4.02(e). If Tenant does elect to pursue the Tax
Contest under the circumstances described above, then Tenant shall furnish such
security, if any, as may be required in the Tax Contest proceedings.
Section 4.03. UTILITIES. Tenant shall pay, directly to the appropriate
supplier, the cost of all natural gas, heat, light, power, sewer service,
telephone, fiber optic, cable or other telecommunications or data delivery
services, water, refuse disposal and other utilities and services supplied to
the Property during the Lease Term. However, if any services or utilities are
jointly metered with other property, Landlord shall make a reasonable
determination of Tenant's proportionate share of the cost of such utilities and
services and Tenant shall pay such share to Landlord with Tenant's next monthly
installment of Base Rent, consistent with Section 4.01 above. Landlord's
determination shall take into consideration the uses being made of the Building,
the uses being made of the other building in the Project, and any differences in
costs imposed by the utility providing entity. Tenant acknowledges and agrees
that (1) this Lease is entirely separate and distinct from and independent of
any and all agreements that Tenant may at any time enter into with any third
party for the provision of utility services or any other services, and (2)
Landlord has no obligation of any kind concerning the provision of any such
services. Landlord shall not be liable for any failure to furnish, stoppage of,
or interruption in furnishing any of the services or utilities described in this
Section 4.03, when such failure is not caused by, and does not result from, any
act or omission of Landlord, its agents, permitees, invitees or contractors, and
instead results from accident, breakage or repairs caused by parties other than
Landlord, its agents, permitees, invitees or contractors, or is caused by
strikes, lockouts, labor disputes, labor disturbances, governmental regulation,
civil disturbances, terrorist acts, acts of war, moratorium or other
governmental action, or any other cause beyond Landlord's reasonable control,
and, in such event, Tenant shall not be entitled to any damages, nor shall any
failure or interruption abate or suspend Tenant's obligation to pay rent as
required under this Lease or constitute or be construed as a constructive or
other eviction of Tenant. Further, in the event any governmental authority or
public utility promulgates or revises any law, ordinance, rule or regulation, or
issues mandatory controls or voluntary controls relating to the use or
conservation of energy, water, gas, light or electricity, the reduction of
automobile or other emissions, or the provision of any other utility or service,
Landlord may take any reasonably appropriate action to comply with such law,
ordinance, rule, regulation, mandatory control or voluntary guideline without
affecting Tenant's obligations under this Lease. Tenant recognizes that security
services, if any, provided by Landlord at the Project are for the protection of
Landlord's property, and under no circumstances shall Landlord be responsible
for, and Tenant waives any rights with respect to, providing security or other
protection for Tenant or its employees, invitees or property in or about the
Property or the Building.
Section 4.04. INSURANCE POLICIES.
(a) LIABILITY INSURANCE. Subject to the provisions of Section
4.04(e) below, during the Lease Term, Tenant, at Tenant's sole cost and expense,
shall maintain a policy of commercial general liability insurance (or its
equivalent) insuring Tenant against liability for bodily injury, property damage
(including loss of use of property) and personal injury arising out of Tenant's
use or occupancy of the Property. Tenant shall name Landlord as an additional
insured under such policy, and Tenant shall provide Landlord with an appropriate
insurance certificate so evidencing prior to Tenant's occupancy of the Property,
which certificate shall show Landlord as "an additional insured as required by
contract." The initial per occurrence amount of such insurance shall be Three
Million Dollars ($3,000,000.00) and shall be subject to periodic increase based
upon inflation, increased liability awards, the reasonable recommendations of
Landlord's professional insurance advisors and other relevant factors; provided,
however, that any such increase shall not be required during the first three (3)
Lease Years and shall not exceed those increases reasonably required by prudent
owners of like properties in the Las Vegas metropolitan area. The liability
insurance obtained by Tenant under this Section 4.04(a): shall (i) be primary
and non-contributing except with respect to Landlord's negligence or willful
misconduct; (ii) contain cross-liability endorsements; and (iii) provide
contractual coverage with respect to Tenant's obligations under Section 5.05
below. The amount and coverage of such insurance shall not limit Tenant's
liability nor relieve Tenant of any other obligation under this Lease. Landlord
shall also obtain commercial general liability insurance (or its equivalent)
insuring Landlord against liability for bodily injury, property damage
(including loss of use of property) and personal injury arising out of
ownership, operation, use or occupancy of the Property. The initial per
occurrence amount of such insurance shall be not less than Three Million Dollars
($3,000,000.00) and shall be increased in amount and at times coincident with
Tenant's required liability coverage amount increases provided above. The
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policy obtained by Landlord shall not be contributory and shall not provide
primary insurance except with respect to Landlord's negligence or willful
misconduct. The policy obtained by Landlord shall provide contractual coverage
with respect to Landlord's obligations under Section 5.05 below. In addition to
the foregoing, both Landlord and Tenant shall obtain commercial automobile
liability coverage with combined single limit coverage of One Million Dollars
($1,000,000.00) for bodily injury and property damage, which coverage shall
include owned, non-owned and hired automobile liability for vehicles driven on
or about the Property by their respective employees. Landlord shall have Tenant
named as an additional insured on any policy of liability insurance obtained
relative to the Common Areas.
(b) PROPERTY INSURANCE. Except as otherwise provided herein, and
subject to the provisions of Section 4.04 (e) below, during the Lease Term,
Tenant shall maintain policies of insurance covering loss of or damage to the
Building Shell Improvements (including Common Area Improvements on the Building
Premises other than, and excluding, the ESFR System [as defined in Section
4.05(a)]) and Tenant Improvements, in the full amount of their replacement
value, with such policies providing protection against loss or damage due to
fire or other casualties covered within the classification of fire and extended
coverage. Such insurance coverage shall be effected by adding the Building Shell
Improvements (including the Common Area Improvements located on the Building
Premises, other than, and excluding the ESFR System) and the Tenant's
Improvements to Tenant's schedule of insured values on its property coverage
insurance policies, and shall be thereby insured against such other casualties
as Tenant may elect to obtain relative to its other similar properties, which
coverages may, at Tenant's election, include vandalism, malicious mischief,
sprinkler leakage, flood coverage, earthquake coverage and/or terrorism
coverage. All policies required under this Section 4.04(b) shall be written as
primary policies, not contributing with and not supplemental to any property
insurance coverage that Landlord may carry, and shall name Tenant, Landlord and
Landlord's mortgage lender as loss payees as respects the Base Building Shell
Improvements. Tenant shall be responsible for payment of the entirety of any
deductible amount under Tenant's insurance policies. Neither Landlord nor Tenant
shall do or permit anything to be done which invalidates any such insurance
policies.
(c) PAYMENT OF PREMIUMS. Tenant shall pay all premiums for the
insurance policies described in Sections 4.04(a) and (b), except Landlord shall
pay all premiums for liability insurance which Landlord is required to obtain as
provided in Section 4.04(a) above. Subject to the provisions of Section 2.03
above and Section 4.04 (e) below, prior to the Lease Commencement Date Tenant
shall deliver to Landlord the "Acord Form" (or such other reasonable substitute
form as may then be customarily accepted by Landlord's and Landlord's mortgage
lender if the Acord Form is no longer available) certificates of insurance
evidencing insurance coverage which Tenant is required to maintain under this
Section 4.04. Upon the expiration of any such policy, Tenant shall deliver to
Landlord a certificate evidencing renewal of such policy without a lapse in
coverage. All such certificates of insurance shall be issued by an officer or
agent of the insurer. Landlord or Landlord's mortgage lender may request
commercially reasonable modifications to certificates of insurance provided by
Tenant. If so, Tenant shall expend commercially reasonable efforts to obtain
such modifications or to obtain issuance of a modified certificate. If Tenant is
unsuccessful in those efforts, Tenant shall provide to Landlord or Landlord's
mortgage lender written certification by an officer of Tenant, that with respect
to the particular required insurance coverage, such coverage is in force and
effect, or that Tenant is self-insuring such coverage in accordance with the
provisions of Section 4.04(e) below. If Landlord maintains a property casualty
insurance policy with a schedule for "contingent coverage" for multiple Landlord
properties (with claim proceeds payable only if Tenant or Tenant's insurer fails
to respond to the claim), and if Landlord's mortgage lender requires the Base
Building Shell Improvements to be added to such schedule, Tenant shall reimburse
Landlord for seventy-five percent (75%) of the premium cost of adding the Base
Building Shell Improvements to such schedule. In such event, Tenant shall
reimburse Landlord for such premium cost within thirty (30) days following
Tenant's receipt of Landlord's invoice therefor.
(d) GENERAL INSURANCE PROVISIONS.
(i) Any insurance that Tenant is required to maintain under
this Lease shall include the carrier's standard provision for thirty (30) days'
notice to Landlord prior to any cancellation or modification of such coverage,
including the cancellation or modification of any required endorsements.
(ii) If Tenant fails to deliver any certificate to Landlord
required under this Lease within the prescribed time period or if such policy is
cancelled or modified contrary to the requirements of this Lease during the
Lease Term without Landlord's consent (unless such policy is not in force or has
been cancelled or
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modified because Tenant has qualified for and elected to self-insure pursuant to
Section 4.04(e) below), such failure, cancellation or modification shall
constitute a material default under this Lease if not cured by Tenant following
written notice from Landlord pursuant to Section 10.02 of this Lease.
(iii) Tenant shall maintain all insurance required under this
Lease with companies duly authorized to issue insurance policies in Nevada and
holding a Financial Strength Rating of "A" or better, and a Financial Size
Category of "VIII" or larger, based on the most recent published ratings of the
A.M. Best Company. If at any time during the Lease Term, Tenant is unable to
maintain the insurance required under this Lease, Tenant shall nevertheless
maintain insurance coverage which is customary and commercially reasonable in
the insurance industry for Tenant's type of business, as that coverage may
change from time to time.
(iv) Notwithstanding anything in this Lease to the contrary,
Landlord and Tenant each hereby waives any and all rights of recovery against
the other, or against the members, managers, officers, employees, agents or
representatives of the other (whether such right of recovery arises from a claim
based on negligence or otherwise), for loss of or damage to its property or the
property of others under its control, if such loss or damage is covered by any
insurance policy required under the terms of this Lease (or other insurance
coverage not required by this Lease) and which is active and in force at the
time of such loss or damage. Upon obtaining the required policies of insurance,
Landlord and Tenant shall give notice to the insurance carriers of this mutual
waiver of subrogation and shall obtain any policy endorsements required therefor
by any such policy.
(v) Neither Landlord nor Tenant shall do or permit to be done
any act or thing upon the Property or the Project which would jeopardize or be
in conflict with the property insurance policies covering the Project or
fixtures or property in the Project.
(vi) During the Lease Term, Tenant, at Tenant's sole cost and
expense, shall maintain workers' compensation insurance as required by Nevada
law, and employer's liability insurance coverage with a limit of One Million
Dollars ($1,000,000.00) in Constant Dollars (as defined in Section 6.05(b)
below).
(vii) If Tenant carries any of the liability insurance
required hereunder in the form of a blanket policy, any certificate required
hereunder shall make specific reference to the Property.
(viii) Landlord or Landlord's mortgage lender shall not be
limited in the proof of any damages which Landlord or Landlord's mortgage lender
may claim against Tenant arising out of or by reason of Tenant's failure to
provide and keep in force insurance, as provided above, to the amount of the
insurance premium or premiums not paid or incurred by Tenant and which would
have been payable under such insurance; but Landlord and Landlord's mortgage
lender shall also be entitled to recover as damages for such breach, the
uninsured amount of any loss, to the extent that it would have been insured.
Tenant shall self insure any deductibles for the insurance required to be
carried by Tenant in this Section 4.04.
(ix) Insurance claims by reason of damage to or destruction of
any portion of the Property shall be adjusted by Tenant; provided, however, that
although Tenant shall make the final decision with respect to any such
adjustment, with respect to any claim regarding damage to or destruction of the
Base Building Shell Improvements in excess of $200,000.00, promptly after such
damage or destruction, Tenant shall advise Landlord and Landlord's mortgage
lender of such occurrence and consult with Landlord and Landlord's mortgage
lender throughout the process of adjusting any such claim, and provided further
that both Landlord and Landlord's mortgage lender are fully advised as to all
matters on a current basis. Landlord shall not be required to prosecute any
claim against, or to contest any settlement proposed by Tenant or an insurer.
Tenant may, at its expense, prosecute any such claim or contest any such
settlement in the name of Landlord, Tenant or both, and Landlord will join
therein at Tenant's written request upon the receipt by Landlord of an indemnity
from Tenant against all costs, liabilities and expenses in connection therewith.
(e) SELF-INSURANCE OPTION. Tenant shall have the right to satisfy
its insurance obligations under this Lease by means of self-insurance to the
extent of all or part of the insurance required hereunder so long as (a) such
self-insurance is permitted under all laws applicable to Tenant and/or the
Property at the time in question, and (b) Tenant maintains a tangible net worth
(as shown by its audited financial statements prepared in accordance with
generally accepted accounting principles) of not less than Two Hundred Fifty
Million Dollars
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($250,000,000.00) in Constant Dollars; and (c) Tenant shall, not less than
annually, provide Landlord an audited financial statement, prepared in
accordance with generally accepted accounting principles, showing the required
tangible net worth (provided, that Tenant need not make such a delivery if its
financial statement is generally available to the public through Tenant's
filings with a governmental authority). If Tenant is a Tenant Affiliate of the
original Tenant, the foregoing $250,000,000.00 net worth requirement shall be
reduced to One Hundred Million Dollars ($100,000,00.00) so long as the original
Tenant maintains a tangible net worth of $250,000,000.00 and remains liable
under this Lease in accordance with the provisions of Section 9.05 below.
"Self-insure" shall mean that Tenant is itself acting as though it were the
third-party insurer providing the insurance required under the provisions of
this Lease, and Tenant shall pay any amounts due in lieu of insurance proceeds
because of self-insurance. To the extent Tenant chooses to provide any insurance
required by this Lease by "self-insurance," then Tenant shall have all of the
obligations and liabilities of an insurer, and the protection afforded Landlord,
Landlord's mortgage lender, and the Property shall be the same as if provided by
a third-party insurer under the coverages required under this Lease. Without
limiting the generality of the foregoing, all amounts which Tenant pays or is
required to pay and all losses or damages resulting from risks for which Tenant
has elected to self-insure shall be subject to the waiver of subrogation
provisions of Section 4.04(d)(iv) of this Lease, and shall not limit Tenant's
indemnification obligations set forth in Section 5.05 of this Lease. In the
event that Tenant elects to self-insure and an event or claim occurs for which a
defense and/or coverage would have been required to be furnished by Tenant under
the provisions of Section 4.04(a) from a third-party insurer, Tenant shall
undertake the defense of the claim (if applicable), including a defense of
Landlord (if applicable), at Tenant's sole cost and expense, and use its own
funds to pay the claim or replace any property or otherwise provide the funding
which would have been available from insurance proceeds but for such election by
Tenant to self-insure. In the event that Tenant elects to self-insure any
coverage required to be insured by Tenant in this Lease, upon written request
from Landlord, Tenant shall provide Landlord and Landlord's mortgage lender with
written confirmation from Tenant (certified to by an officer of Tenant) of that
coverage, in form reasonably acceptable to Landlord and Landlord's mortgage
lender, which may supplement, but not replace the certificates of insurance to
be provided by Tenant pursuant to Section 4.04(c) above for insurance
obligations Tenant chooses not to self-insure.
Section 4.05. COMMON AREAS; USE, MAINTENANCE AND COSTS.
(a) COMMON AREAS. As used in this Lease, "COMMON AREAS" shall mean
those areas within the Project designated as such on Exhibit "A" to this Lease.
If required by law to do so or with Tenant's prior written consent, Landlord,
from time to time, may change the size, location, nature and use of Common Areas
and increase or decrease Common Areas land and/or facilities. Tenant
acknowledges that such legally required activities may result in an
inconvenience to Tenant. Such activities and changes are permitted so long as
they do not permanently and materially affect Tenant's use of the Property.
Although not a part of the Common Areas, the cost of maintaining, testing, and
operating the components of the Project's ESFR fire suppression system,
including the pump house located on the Building Premises, are included within
the Common Area Costs (defined below). Subject to the provisions of Section 5.06
below, Landlord shall be provided access to such pump house for periodic
testing, but no other tenants in the Project shall have such access. The
Project's ESFR fire suppression system, consisting of the pump house, and those
other components of the system that serve, service and benefit both the Building
and the other building in the Project, are collectively referred to herein as
the "ESFR SYSTEM." The (i) ESFR System, (ii) real property improvements,
landscaping, equipment, systems and fixtures located within the Common Areas and
(iii) utility lines within the Common Areas and used in common by tenants of the
Project are collectively referred to herein as "COMMON AREA IMPROVEMENTS."
Notwithstanding any language to the contrary in this Lease, Tenant acknowledges
and agrees that the defined term "ESFR System" does not include those components
of the Project's ESFR fire suppression system which are included within the
Building and which serve, service and benefit only the Building, to the
exclusion of the other building in the Project, and Tenant further agrees that
such components will be treated as part of the Building for purposes of Section
4.04(b) above and as part of the Base Building Shell Improvements for purposes
of Section 7.01 below.
(b) USE OF COMMON AREAS. Tenant shall have the nonexclusive right
(in common with other tenants in the Project) to use the Common Areas for the
purposes intended, subject to such reasonable rules and regulations as Landlord
may establish from time to time. Tenant shall abide by such rules and
regulations and shall use its best effort to cause others who use the Common
Areas with Tenant's express or implied permission to abide by Landlord's rules
and regulations. At any time, Landlord may close any Common Areas to perform any
acts in
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the Common Areas as, in Landlord's judgment, are desirable to improve the
Project. Tenant shall not interfere with the rights of Landlord, other tenants
or any other person entitled to use the Common Areas.
Notwithstanding the foregoing provisions of this Section 4.05,
Tenant, at its cost and subject to its compliance with Applicable Laws, shall
have the right to establish vehicle parking spaces in the Common Areas, but only
within the northerly twenty-five feet (25') of the Building Premises (excluding
areas that are required for fire lanes) by installation and placement of
pavement striping and other parking improvements. Tenant, its permitted
Subtenants, and its and their employees, contractors, customers and other
business invitees shall be entitled to exclusive use of any parking spaces so
established. Such reserved parking improvements shall not be considered Common
Area Improvements and shall be maintained by Tenant pursuant to Section 6.04
below. In the event of use of such parking spaces by other tenants in the
Project or other parties, Landlord shall take all commercially reasonable steps
to curtail such use by other parties and preserve to Tenant and its permitted
Subtenants the use thereof, whether by use of parking reservation signs, or
otherwise.
(c) MAINTENANCE OF COMMON AREAS. Landlord, and not Tenant, shall
maintain the Common Areas and all Common Area Improvements in good order,
condition and repair (including replacement, as necessary), and shall operate
the Project as a first-class industrial/commercial real property development.
Subject to the provisions of Section 4.05(e), Tenant shall pay Tenant's Pro Rata
Share (as determined below) of all costs incurred by Landlord for the operation
and maintenance of the Common Areas and Common Area Improvements (the "COMMON
AREA COSTS"). Common Area Costs include, but are not limited to, all costs and
expenses for the following: utilities, water and sewage charges; maintenance of
signs (other than tenants' signs); maintenance of the ESFR System (including
testing, monitoring and servicing); maintenance of landscaped areas; maintenance
of utility lines within the Common Areas and which are used in common by tenants
of the Project, to the extent such maintenance responsibility is not assumed by
the utility provider; premiums for liability, property damage, fire and other
types of casualty insurance (if applicable) on the Common Area Improvements;
premiums for worker's compensation insurance (if applicable); all property taxes
and assessments levied on or attributable to the Common Areas and all Common
Areas Improvements (if applicable); appropriately prorated personal property
taxes levied on or attributable to personal property used in connection with the
Common Areas; appropriately prorated straight-line depreciation on personal
property owned by Landlord which is consumed in the operation or maintenance of
the Common Areas; the cost of improvements made subsequent to the initial
development of the Common Areas to comply with the requirements of any law,
ordinance, code, rule or regulation; appropriately prorated rental or lease
payments paid by Landlord for rented or leased personal property used in the
operation or maintenance of the Common Areas; appropriately prorated fees for
required licenses and permits; repairing, resurfacing, repaving, maintaining,
painting, lighting, cleaning, refuse removal, security and similar items for the
Common Areas; and reserves for sealing and restriping and/or resurfacing and
repaving of the Common Areas paved areas. Except for payment of Tenant's Pro
Rata Share of the Common Area Costs associated with the operation and
maintenance of the ESFR System, as provided in this Section, Tenant shall have
no obligation or responsibility whatsoever for the maintenance, repair or
replacement of the ESFR System or any portion thereof. Landlord may cause any or
all of such services to be provided by third parties and the cost of such
services shall be included in Common Area Costs. Common Area Costs shall not
include depreciation of Common Area Improvements or any real property, real
property improvements, or equipment, machinery or fixtures which are part of the
Common Areas.
(d) ROUTINE MAINTENANCE. Consistent with Section 4.05(c) above,
Landlord shall maintain, as Common Area Costs, the landscaped and paved areas
within the Common Areas. Such maintenance shall include gardening, tree
trimming, replacement or repair of landscaping, landscape irrigation systems and
similar items. Such maintenance shall also include sweeping and cleaning of
asphalt, concrete or other surfaces on the driveway, parking areas, yard areas,
loading areas or other paved or covered surfaces in Common Areas. In connection
with Landlord's obligations under this Section 4.02(d), Landlord may enter into
a contract with a contractor of Landlord's choice to provide some (but not
necessarily all) of the maintenance services listed above. Subject to the
provisions of Section 4.05(e), Tenant shall pay its Pro Rata Share of the
monthly cost of such contract relative to the Common Areas, as part of its share
of the monthly Common Area Costs.
(e) TENANT'S SHARE AND PAYMENT. Tenant shall pay Tenant's Pro Rata
Share of all Common Area Costs (prorated for any fractional month) upon written
notice from Landlord that such costs have been incurred and are due and payable,
and in any event prior to delinquency. Tenant's "PRO RATA SHARE" shall be as
stated in Section 1.10(b) above, subject to a proportionate equitable adjustment
if the size of the Common Areas
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are adjusted pursuant to Section 4.05(a) above. Landlord may, at Landlord's
election, estimate in advance and charge to Tenant as Common Area Costs, all
Real Property Taxes for which Tenant is liable under Section 4.02(c) of this
Lease, and all other Common Area Costs payable by Tenant hereunder. At
Landlord's election, such statements of estimated Common Area Costs shall be
delivered monthly, quarterly or at any other periodic intervals to be designated
by Landlord; provided, however, that unless otherwise notified by Landlord,
Landlord shall bill Tenant monthly in advance for the estimated Common Area
Costs (other than Real Property Taxes, which shall be billed quarterly) and
Tenant shall pay Landlord the amount of such costs, as Additional Rent. Landlord
may adjust such estimates annually based upon Landlord's experience and
reasonable anticipation of costs. Such adjustments shall be effective as of the
next rent payment date after notice to Tenant. Within one hundred twenty (120)
days after the end of each calendar year of the Lease Term, Landlord shall
deliver to Tenant a statement prepared in accordance with generally accepted
accounting principles setting forth, in reasonable detail, the Common Area Costs
paid or incurred by Landlord during the preceding calendar year and Tenant's Pro
Rata Share. Landlord shall thereafter deliver to Tenant copies of all
documentation that Tenant may reasonably request relative to the Common Area
Costs paid or incurred by Landlord during that period, including, but not
limited to, copies of service contracts, invoices, statements and billings,
together with evidence of payments by Landlord, and including the formulas and
other accounting bases by which Landlord has computed Tenant's billings for a
Common Area Costs. Landlord shall retain all such documentation for a period of
not less than three (3) years. Following receipt of such statement and any such
documentation, there shall be an adjustment between Landlord and Tenant, with
payment to or credit given by Landlord (as the case may be) so that Landlord
shall receive the entire amount of Tenant's share of such costs and expenses for
such period and Tenant shall pay only the amount for which Tenant is obligated
for such period. The provisions of this Section 4.05(e) shall survive the
expiration or earlier termination of the Lease Term.
(f) TENANT'S USE OF LANDLORD'S CONTRACTORS. Upon Tenant's written
request, but not more than annually, Landlord shall provide to Tenant a schedule
of the services provided by Landlord in performing its obligations under Section
4.05(c) and Section 4.05(d) above (the "CAM SERVICES LIST") together with the
names and addresses of contractors providing such services and such other
information relative thereto as Tenant may reasonably request. Landlord shall
make available for hiring by Tenant, and Tenant shall have the right to contract
with, any such contractor to perform tasks for which Tenant is responsible under
the provisions of Section 6.04 below.
Section 4.06. LATE CHARGES. Tenant's failure to pay rent promptly may
cause Landlord to incur unanticipated costs. The exact amount of such costs are
impractical or extremely difficult to ascertain. Such costs may include, but are
not limited to, processing and accounting charges and late charges which may be
imposed on Landlord by any ground lease, mortgage or trust deed encumbering the
Property. Therefore, if Landlord does not receive any rent payment within ten
(10) business days after it becomes due, subject to the subsequent provisions of
this Section 4.06 Tenant shall pay Landlord a late charge equal to five percent
(5%) of the overdue amount. The parties agree that such late charge represents a
fair and reasonable estimate of the costs Landlord will incur by reason of such
late payment. Notwithstanding anything to the contrary in this Section 4.06,
such late charge shall not be incurred unless Tenant fails to deliver such
delinquent payment within three (3) business days following Tenant's receipt of
written notice from Landlord of the delinquency, amount and original due date of
the payment and demanding its payment; provided, however, that Landlord is under
no obligation to provide more than two (2) such notices in any consecutive
12-month period. Further, if Landlord fails to receive any payment or give
Tenant credit for receipt of any payment as a result of errors, omissions or
oversights of Landlord, its employees or bankers, or as a result of any changes
made by Landlord with respect to its bankers or personnel, no such late charges
shall be imposed, and any notices given by Landlord relative thereto shall not
constitute one of the two notices provided for in the immediately proceeding
sentence.
Section 4.07. INTEREST ON PAST DUE OBLIGATIONS. In addition to any late
charge imposed pursuant to Section 4.06 above, but subject to the subsequent
provisions of this Section 4.07, any amount owed by Tenant to Landlord which is
not paid within thirty (30) days when due shall bear interest at the rate of ten
percent (10%) per annum from the due date of such amount ("INTEREST"); provided,
however, that no Interest shall be payable on any late charges imposed on Tenant
under this Lease. The payment of interest on such amounts shall not excuse or
cure any default by Tenant under this Lease. If the interest rate specified in
this Section 4.07 is higher than the rate permitted by law, such interest rate
is hereby decreased to the maximum legal interest rate permitted by law.
Notwithstanding the terms of this Section 4.07, such default interest shall not
be imposed unless Tenant fails to deliver such delinquent payment within three
(3) business days following Tenant's receipt of written notice from
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Landlord of the delinquency, amount and original due date of the payment and
demanding its payment; provided, however, that Landlord is under no obligation
to provide more than two (2) such notices in any consecutive 12-month period.
Further, if Landlord fails to receive any payment or give Tenant credit for
receipt of any payment as a result of errors, omissions or oversights of
Landlord, its employees or bankers, or as a result of any changes made by
Landlord with respect to its bankers or personnel, no interest shall be imposed,
and any notices given by Landlord relative thereto shall not constitute one of
the two notices provided for in the immediately proceeding sentence.
Section 4.08. MANAGEMENT FEE. Tenant pay Landlord, for Landlord's
supervision and management of the Project, a management fee not to exceed one
percent (1%) of the Base Rent payable under this Lease. Such fee shall be
payable monthly by Tenant, as Additional Rent, as and when the monthly Base Rent
is paid.
ARTICLE FIVE USE OF PROPERTY
Section 5.01. PERMITTED USES. Tenant may use the Property only for the
Permitted Uses set forth in Section 1.06 above.
Section 5.02. MANNER OF USE. Tenant shall not cause or permit the Property
to be used in any way which constitutes a violation of any law, statute,
ordinance, or governmental regulation or order, or other governmental
requirement now in force or which may hereafter be enacted or promulgated
(collectively, "APPLICABLE LAWS"), or which unreasonably interferes with the
rights of other tenants of Landlord, or which constitutes a nuisance or waste.
Tenant shall obtain and pay for all permits required for Tenant's occupancy of
the Property, and for all business licenses, and shall promptly take all actions
necessary to comply with all applicable statutes, ordinances, rules,
regulations, orders and requirements regulating the use by Tenant of the
Property, including without limiting to the Occupational Safety and Health Act.
Notwithstanding the foregoing, Landlord shall, at Tenant's sole cost and
expense, cooperate with Tenant in executing permitting applications and
performing other ministerial acts reasonably necessary to enable Tenant to
obtain a High Pile Stock Permit (or comparable permit) from the applicable
governmental authority, if applicable. Tenant, at Tenant's sole cost and
expense, shall be responsible for the installation of any fire hose valves,
draft curtains, smoke venting and any additional fire protection systems that
may be required by the fire department or any governmental agency, save and
except for the standard ESFR fire suppression systems and pump and any such
valves, draft curtains, smoke venting and additional fire protection systems
that are part of the Building Shell Improvements to be constructed at Landlord's
cost and expense.
Tenant shall, at its sole cost and expense, promptly comply with any
Applicable Laws which relate to (or are triggered by) (i) Tenant's use of the
Property, and (ii) any alteration or any tenant improvements made by Tenant or
at the request of Tenant. Should any standard or regulation now or hereafter be
imposed on Tenant by any federal, state or local governmental body charged with
the establishment, regulation and enforcement of occupational, health or safety
standards, then Tenant agrees, at its sole cost and expense, to comply promptly
with such standards or regulations so long as Tenant is not actively contesting
the same. The final, unappealed or unappealable judgment of any court of
competent jurisdiction or the admission of Tenant in any judicial action,
regardless of whether Landlord is a party thereto, that Tenant has violated any
Applicable Laws, shall be conclusive of that fact as between Landlord and
Tenant. Tenant shall promptly notify Landlord in writing of any water
infiltration at the Property indicating the need for a repair that is the
responsibility of Landlord under this Lease and any other material water
infiltration in the Building.
Section 5.03. HAZARDOUS MATERIALS.
5.03.1 DEFINITIONS.
A. "HAZARDOUS MATERIAL" means any substance, whether solid, liquid
or gaseous in nature:
(i) the presence of which requires remediation under any
federal, state or local statute, regulation, ordinance, order, action or policy
relating to the protection of human health or the environment, or
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(ii) which is or becomes defined as a "hazardous waste,"
"hazardous substance," pollutant or contaminant under any federal, state or
local statute, regulation, rule or ordinance or amendments thereto including,
without limitation, the Comprehensive Environmental Response, Compensation and
Liability Act (42 U.S.C. section 9601 et seq.) and/or the Resource Conservation
and Recovery Act (42 U.S.C. section 6901 et seq.), the Hazardous Materials
Transportation Act (49 U.S.C. section 1801 et seq.), the Federal Water Pollution
Control Act (33 U.S.C. section 1251 et seq.), the Clean Air Act (42 U.S.C.
section 7401 et seq.), the Toxic Substances Control Act, as amended (15 U.S.C.
section 2601 et seq.), and the Occupational Safety and Health Act (29 U.S.C.
section 651 et seq.), as these laws have been amended or supplemented; or
(iii)which is toxic, explosive, corrosive, flammable,
infectious, radioactive, carcinogenic, mutagenic, or otherwise hazardous and is
or becomes regulated by any governmental authority, agency, department,
commission, board, agency or instrumentality of the United States, the State of
Nevada or any political subdivision thereof; or
(iv) which contains gasoline, diesel fuel or other petroleum
hydrocarbons; or
(v) which contains polychlorinated biphenyls (PCBs), asbestos
or urea formaldehyde foam insulation; or
(vi) which contains radon gas.
B. "ENVIRONMENTAL REQUIREMENTS" means all applicable present and
future:
(i) statutes, regulations, rules, ordinances, codes, licenses,
permits, orders, approvals, plans, authorizations, concessions, franchises, and
similar items (including, but not limited to those pertaining to reporting,
licensing, permitting, investigation and remediation), of all Governmental
Agencies relating to the manufacture, processing, distribution, use, treatment,
storage, disposal, transport or handling of Hazardous Materials; and
(ii) all applicable judicial, administrative, and regulatory
decrees, judgments, and orders relating to emissions, discharges, releases, or
threatened releases of Hazardous Materials into the air, surface water,
groundwater or land, or relating to the manufacture, processing, distribution,
use, treatment, storage, disposal, transport, or handling of Hazardous
Materials.
C. "ENVIRONMENTAL DAMAGES" means all claims, judgments, damages,
losses, penalties, fines, liabilities (including strict liability),
encumbrances, liens, costs, and expenses (including the expense of investigation
and defense of any claim, whether or not such claim is ultimately defeated, or
the amount of any good faith settlement or judgment arising from any such claim)
of whatever kind or nature, contingent or otherwise, matured or unmatured,
foreseeable or unforeseeable (including without limitation reasonable attorneys'
fees and disbursements and consultants' fees) any of which are incurred at any
time as a result of the existence of Hazardous Materials upon, about, or beneath
the Property or migrating or threatening to migrate from the Property, or the
existence of a violation of Environmental Requirements pertaining to the
Property and the activities thereon. Environmental Damages include, without
limitation:
(i) compensatory damages for personal injury, or injury to
property or natural resources occurring upon or off of the Property, including
interest, penalties and damages arising from claims brought by or on behalf of
employees of Tenant;
(ii) fees, costs or expenses reasonably incurred for the
services of outside environmental counsel, consultants, contractors, experts,
laboratories and all other costs incurred in connection with the investigation
or remediation of such Hazardous Materials or violation of such Environmental
Requirements, including, but not limited to, the preparation of any feasibility
studies or reports or the performance of any cleanup, remediation, removal,
response, abatement, containment, closure, restoration or monitoring work
required by any Governmental Agency or reasonably necessary to make full
economic use of the Property or any other property in a manner consistent with
its current use or otherwise expended in connection with such conditions, and
including
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without limitation any attorneys' fees, costs and expenses incurred in enforcing
the provisions of this Section 5.03 or collecting any sums for Environmental
Damages due hereunder pursuant to Section 12.01 below;
(iii) liability to any third person or Governmental Agency to
indemnify such person or Governmental Agency for costs expended in connection
with the items referenced in subparagraph (ii) above; and
(iv) diminution in the fair market value of the Property;
provided, however, that this measure of Environmental Damages shall be
inapplicable if, upon expiration or earlier termination of this Lease, there
will be no remaining residual leasehold interest for Landlord under the Master
Lease.
D. "GOVERNMENTAL AGENCY" means all governmental agencies,
departments, commissions, boards, bureaus or instrumentalities of the United
States, states, counties, cities and political subdivisions thereof.
E. The "TENANT GROUP" means Tenant, Tenant's successors, officers,
members, managers, directors, assignees, agents, employees, contractors,
invitees, permitees or other parties under the supervision or control of Tenant
or entering the Property during the Lease Term with the permission or knowledge
of Tenant.
F. The "LANDLORD GROUP" means Landlord, Landlord's successors,
officers, members, managers, directors, assignees, agents, employees,
contractors, invitees, permitees, affiliates, other tenants and other parties
under the supervision or control of Landlord or entering the Property or Project
during the Lease Term with the permission or knowledge of Landlord, other than
any party in the Tenant Group.
5.03.2 PROHIBITIONS.
A. Other than normal quantities of general office and cleaning
supplies and except as specified on Exhibit "D" attached hereto, Tenant shall
not cause, permit or suffer any Hazardous Material to be brought upon, treated,
kept, stored, disposed of, discharged, released, produced, manufactured,
generated, refined or used upon, about or beneath the Property by the Tenant
Group, or any other person without the prior written consent of Landlord;
provided, however, if Tenant is the original Tenant, a Tenant Affiliate of the
original Tenant or a regulated public utility, prior written notification to
Landlord shall be sufficient without the necessity of obtaining Landlord's
consent. If Landlord's consent is required, Landlord shall allow Tenant's use of
such other Hazardous Materials if Tenant establishes, to Landlord's reasonable
satisfaction, that the use of such substances poses no materially greater risk
of contamination to the Property than do Tenant's existing activities in view of
(a) quantities, toxicity and other properties of the proposed new Hazardous
Materials, (b) precautions Tenant agrees to take to prevent a release, (c)
Tenant's current financial condition as it relates to its ability to fund a
major clean-up, and (d) Tenant's policy and historical record respecting its
willingness to respond to any such clean-up. Prior to the Lease Commencement
Date (for those Hazardous Materials described on Exhibit "D") and upon
introduction of other Hazardous Materials on the Property (for other Hazardous
Materials later used on the Property), Tenant shall make available to Landlord
for review and copying: (a) any written handling, storage, use and disposal
procedures of Tenant; and (b) any "community right to know" plans or disclosures
and/or emergency response plans which Tenant is required to supply to local
Governmental Agencies pursuant to any Environmental Requirements.
B. Tenant shall cause the Tenant Group to comply with all
Environmental Requirements relating to Property.
C. Tenant shall keep the Property free and clear from any lien,
imposed pursuant to section 107(f) of the Superfund Amendments and
Reauthorization Act of 1986 (42 U.S.C. section 9607(l)) or any similar state
statute as a result of the acts or omissions of the Tenant Group.
D. Except as specified on Exhibit "D" attached hereto, Tenant shall
not install any below grade Storage Tank (as defined below) on the Building
Premises or install, operate or maintain any sump, pit, pond or lagoon on the
Property without Landlord's prior written consent. No Tenant other than the
original Tenant, a Tenant Affiliate of the original Tenant or a Tenant that is a
regulated public utility shall install any below grade Storage Tank on the
Additional Property without the prior written consent of Landlord. Except as
specified on Exhibit "D" attached hereto, Tenant shall not install any Storage
Tank on the Property except after prior written
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notification to Landlord. "STORAGE TANK" means a stationary tank used to contain
or accumulate Hazardous Materials and that has a storage capacity of more than
five hundred (500) gallons.
5.03.3 INDEMNITY.
A. Subject to the provisions of this Section 5.03.3, Tenant, its
successors and assigns agree to indemnify, defend, reimburse and hold harmless:
(i) Landlord; and
(ii) any other person who acquires all or a portion of the
Property in any manner (including purchase at a foreclosure sale) or who becomes
entitled to exercise the rights and remedies of Landlord under this Lease; and
(iii) the directors, officers, shareholders, employees,
partners, members, managers, agents, contractors, subcontractors, affiliates,
lessees, mortgagees, trustees, heirs, devisees, successors, and assigns and
invitees of such persons;
from and against any and all Environmental Damages which are caused by the
activities or negligence of the Tenant Group or which result from the breach of
any warranty or covenant or the inaccuracy of any representation of Tenant
contained in this Lease, or by Tenant's remediation of the Property or failure
to meet its obligations contained in this Section 5.03. Notwithstanding anything
in the foregoing to the contrary, Tenant, its successors and assigns shall have
no obligation to indemnify, defend, reimburse or hold harmless any of the
foregoing parties from and against any Environmental Damages (i) which are
caused by the activities or negligence of any member of the Landlord Group or
any of the foregoing parties or any agents, contractors, subcontractors, experts
or licensees of any member of the Landlord Group or any of the foregoing
parties, (ii) which result from the breach of any warranty or covenant or the
inaccuracy of any representation of Landlord in this Lease, or which are
contrary to any condition warranted or represented by Landlord in this Lease,
(iii) which are incurred as a result of the existence of Hazardous Materials
upon, about or beneath the Property at the time of Substantial Completion of the
Tenant Improvements), or (iv) which result from or relate to Hazardous Materials
that migrate to, or threaten to migrate to the Property from a location other
than the Property and are not the result of the activities or negligence of the
Tenant Group.
B. The obligations contained in this Section 5.03.3 shall include,
but not be limited to, the burden and expense of defending all claims, suits and
administrative proceedings, even if such claims, suits or proceedings are
groundless, false or fraudulent, and conducting all negotiations of any
description, and paying and discharging, when and as the same become due, any
and all judgments, penalties or other sums due against such indemnified persons.
Landlord, at its sole expense, may employ additional counsel of its choice to
associate with counsel representing Tenant.
C. Landlord shall have the right but not the obligation to join and
participate in, at Landlord's sole expense, any legal proceedings or actions
initiated in connection with Tenant's activities. Landlord may also, at
Landlord's sole expense, negotiate, settle, defend, approve and appeal any
action taken or issued by any applicable governmental authority with regard to
contamination of the Property by a Hazardous Material.
D. The obligations of Tenant in this Section 5.03.3 shall survive
the expiration or termination of this Lease.
5.03.4 OBLIGATION TO REMEDIATE. In addition to the obligation of
Tenant to indemnify Landlord pursuant to this Lease, Tenant shall, upon approval
and demand of Landlord, at its sole cost and expense, and using contractors
approved by Landlord, promptly take all actions to remediate the Property which
are required by (i) any Governmental Agency (ii) the Master Lease (as defined in
Article Seventeen) or (iii) any deed of trust or mortgage of Landlord's
mortgagees lender then encumbering the Property, which remediation is
necessitated from the presence upon, about or beneath the Property, at any time
during or upon termination of this Lease (whether discovered during or following
the Lease Term), of a Hazardous Material or a violation of Environmental
Requirements existing as a result of the activities or negligence of the Tenant
Group. Such actions shall include, but
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not be limited to, the assessment of a known environmental condition of the
Property, the preparation of appropriate feasibility studies, reports or
remedial plans, and the performance of any cleanup, remediation, containment,
operation, maintenance, monitoring or restoration work, whether on or off the
Property, which shall be performed in a commercially reasonable manner and in
conformance with requirements of any Governmental Agency, the Master Lease and
any deed of trust or mortgage of Landlord's mortgagee lender in force against
the Property.
5.03.5 RIGHT TO INSPECT. Following written notice to Tenant of not
less than two (2) business days, Landlord shall have the right at its sole cost
and expense (except as provided below), in its reasonably exercised discretion,
but not the duty, to enter and conduct an inspection of the Property accompanied
by one or more representatives of Tenant, including invasive tests, at any
reasonable time to determine whether Tenant is complying with the terms of this
Lease, including but not limited to the compliance of the Property and the
activities thereon with Environmental Requirements and determination of the
existence of Environmental Damages as a result of the condition of the Property
and activities thereon. Landlord shall have the right, but not the duty, to
retain any independent professional consultant (the "CONSULTANT") to enter the
Property to conduct such an inspection or to review any report prepared by or
for Tenant concerning such compliance. The cost of the Consultant shall be paid
by Landlord unless such investigation discloses a material violation of an
Environmental Requirement by the Tenant Group in which case Tenant shall pay the
reasonable cost of the Consultant. Tenant hereby grants to Landlord, and the
agents, employees, consultants and contractors of Landlord the right to enter
the Property accompanied by one or more representatives of Tenant, and to
perform such tests on the Property as are reasonably necessary to conduct such
reviews and investigations following written notice to Tenant of not less than
two (2) business days. Landlord shall use commercially reasonable efforts to
minimize interference with the business of Tenant and any permitted Subtenants.
Notwithstanding anything in the foregoing or elsewhere in this Lease to the
contrary, the right of Landlord or any representative of Landlord to enter or
have access to Tenant's control room shall be subject to the terms of Section
5.06 below.
5.03.6 NOTIFICATION. If Tenant shall receive notice or other
communication concerning any actual, alleged, suspected or threatened material
violation of Environmental Requirements, or liability of Tenant for
Environmental Damages in connection with the Property or past or present
activities of any person thereon, including but not limited to notice or other
communication concerning any actual or threatened investigation, inquiry,
lawsuit, claim, citation, directive, summons, proceeding, complaint, notice,
order, writ, or injunction, relating to same, then Tenant shall promptly deliver
to Landlord a written description of said violation, liability, or actual or
threatened event or condition, together with copies of any documents evidencing
same. Receipt of such notice shall not be deemed to create any obligation on the
part of Landlord to defend or otherwise respond to any such notification.
If requested by Landlord, Tenant shall disclose to Landlord the
names and amounts of all Hazardous Materials other than general office and
cleaning supplies referred to in Section 5.03.2 of this Lease, which were used,
generated, treated, handled, stored or disposed of on the Property or which
Tenant intends to use, generate, treat, handle, store or dispose of on the
Property and which are either not listed in Exhibit "D" or were not the subject
of any consent of, or notice to Landlord under the provisions of Section 5.03.2.
The foregoing in no way shall limit the necessity for Tenant obtaining
Landlord's consent pursuant to Section 5.03.2 of this Lease, if applicable.
5.03.7 SURRENDER OF PROPERTY. In the ninety (90) days prior to the
expiration or termination of the Lease Term, and for up to thirty (30) days
after the later to occur of: (i) Tenant fully surrenders to Landlord exclusive
possession of the Property; and (ii) the termination of this Lease, Landlord, at
Landlord's cost and expense (except as otherwise provided in Section 5.03.5
above), may have an environmental assessment of the Property performed in
accordance with Section 5.03.5 of this Lease. Tenant shall perform, at its sole
cost and expense, any commercially reasonable clean-up or remedial work
reasonably recommended by the Consultant which is necessary to remove, mitigate
or remediate any Hazardous Materials and/or contamination of the Property caused
by the activities or negligence of the Tenant Group, consistent with the
requirements of Section 5.03.4 above.
5.03.8 ASSIGNMENT AND SUBLETTING. With respect to any assignment of
this Lease or subletting of the Property, if the proposed assignee's or
sublessee's activities on the Property would involve the use, handling, storage
or disposal of material amounts of Hazardous Materials other than those which
are the same or similar to those used by Tenant and in quantities and processes
similar to Tenant's uses in compliance with this Lease, (i) it
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shall be reasonable for Landlord to withhold its consent to such assignment or
sublease in light of the risk of contamination posed by such activities, and/or
(ii) Landlord may impose an additional conditions to such assignment or sublease
which requires Tenant to reasonably establish that such assignee's or
sublessee's activities pose no materially greater risk of contamination to the
Property than do Tenant's permitted activities in view of: (a) the quantities,
toxicity and other properties of the Hazardous Materials used by Tenant in
comparison to those to be used by such assignee or sublessee; (b) the
precautions against a release of Hazardous Materials such assignee or sublessee
agrees to implement; (c) any such assignee's financial condition as it relates
to its ability to fund a major clean-up; and (d) any such assignee's policy and
historical record (if any) respecting its willingness to respond to the clean up
of a release of Hazardous Materials.
5.03.9 STORAGE TANKS. Without limiting the generality of the above
provisions of this Section 5.03, with respect to any above or underground
Storage Tanks to be located on the Property by Tenant, whether with or without
Landlord's consent, Tenant shall keep all permits and registrations current and
shall make available to Landlord for review and copying, all test results
regarding all storage tanks, including without limitation, tightness testing and
release detection results, all submissions to and correspondence with any
Governmental Agency regarding such tests and provide copies of all plans for
responding to releases from all Storage Tanks, including any and all SPCC (spill
prevention control and countermeasure) plans. Tenant shall promptly notify
Landlord of any release or suspected release from such tanks, and shall promptly
implement corrective action and remediation consistent with the provisions of
this Section 5.03. Tenant shall comply with all commercially reasonable requests
by Landlord for modification to any spill prevention, investigation or
remediation plan and shall allow Landlord to conduct its own testing (or, at
Tenant's option, provide Landlord with split samples) at Landlord's sole
expense, following request in writing from Landlord.
5.03.10 SURVIVAL OF HAZARDOUS MATERIALS OBLIGATION. Tenant's
material breach of any of its covenants or obligations under this Section 5.03
not timely cured pursuant to the provisions of Section 10.02(c) below shall
constitute a material default under this Lease. The obligations of Tenant under
this Lease shall survive the expiration or earlier termination of this Lease,
and shall constitute obligations that are independent and severable from
Tenant's covenants and obligations to pay rent under this Lease.
5.03.11 LANDLORD'S REPRESENTATION AND WARRANTY. As of the date
of this Lease, Landlord represents and warrants that to the best of Landlord's
actual knowledge (and except as otherwise disclosed in that certain
environmental assessment report dated July 5, 2006 and prepared by OGI
Environmental LLC, a copy of which has been provided by Landlord to Tenant), the
Property is free of any Hazardous Materials in violation of any Environmental
Requirements, and will be free upon Substantial Completion of the Building Shell
Improvements and the Tenant Improvements. Tenant shall have no liability of any
kind to Landlord for any Environmental Damages resulting from or related to
Hazardous Materials located on, under or about the Property as of the date of
this Lease or upon Substantial Completion of the Building Shell Improvements (or
the Tenant Improvements. As used in this Section, the "actual knowledge" of
Landlord means the actual knowledge of Rodman C. Martin (as opposed to
constructive, implied, or imputed), but without any investigation.
Section 5.04. AUCTIONS AND SIGNS. Tenant shall not conduct or permit any
auctions or sheriff's sales at the Property. Subject to Landlord's prior written
approval, which shall not be unreasonably withheld, delayed or conditioned, and
provided all signs are in keeping with the quality, design and style of the
business park within which the Property is located, Tenant and its permitted
Subtenants, at their cost and expense, may install signs (collectively, "SIGN")
at the Property; provided, however, that (i) the size, color, location,
materials and design of the Sign shall be subject to Landlord's prior written
consent, which shall not be unreasonably withheld, delayed or conditioned; (ii)
the Sign shall comply with all applicable governmental rules and regulations and
the Property's covenants, conditions and restrictions; (iii) the Sign shall not
be painted directly on the Building or attached or placed on the roof of the
Building; and (iv) continuing signage rights shall be contingent upon
maintaining the Sign in a first-class condition. Tenant shall be responsible for
all costs incurred in connection with the design, construction, installation,
repair and maintenance of the Sign. Upon the expiration or earlier termination
of this Lease, Tenant shall cause the Sign to be removed and shall repair any
damage caused by such removal (including, but not limited to, patching and
painting), all at Tenant's sole cost and expense. Any installed signs, notices,
logos, pictures, etc. which have not been approved by Landlord may be removed by
Landlord at Tenant's cost if not removed by Tenant following the applicable
notice and cure period provided in this Lease. Notwithstanding any
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language to the contrary in this Section 5.04, Tenant may, without the prior
consent of Landlord, install typical directional signs at the Property, so long
as the same are in compliance with Applicable Laws.
Section 5.05. INDEMNITY.
5.05.1 TENANT'S INDEMNITY. Tenant shall indemnify, defend, protect
and hold harmless Landlord (and Landlord's agents, employees, contractors, and
property manager) from any and all costs, claims, loss, damage, expense and
liability (including without limitation court costs, litigation expenses, and
reasonable attorneys' fees) incurred in connection with or arising from: (a)
Tenant's use of the Property, including, but not limited to, those arising from
any accident, incident, injury or damage, however and by whomsoever caused
(except to the extent of any claim arising out of the negligence or willful
misconduct of Landlord, its affiliates, employees, agents, contractors, other
tenants or invitees), to any person or property occurring in or about the
Property; (b) the conduct of Tenant's business or anything else permitted by
Tenant to be done in or about the Property; (c) any breach or default in the
performance of Tenant's obligations under this Lease; (d) any misrepresentation
or breach of warranty by Tenant under this Lease; or (e) other acts or omissions
of Tenant. As a material part of the consideration to Landlord, Tenant assumes
all risk of damage to property or injury to persons in or about the Property
arising from any cause from which Tenant is required to indemnify Landlord
pursuant to the foregoing, and Tenant hereby waives all claims in respect
thereof against Landlord, except to the extent of any claim arising out of the
negligence or willful misconduct of Landlord, its agents, contractors, invitees
or permitees. As used in this Section 5.05, acts and omissions of "Tenant" shall
include acts and omissions of Tenant's employees, agents, contractors and
invitees, if applicable. The provisions of this Section 5.05.1 shall survive the
expiration or earlier termination of this Lease with respect to any claims or
liability occurring prior to such expiration or earlier termination, and shall
constitute obligations that are independent and severable from Tenant's
covenants and obligations to pay rent under this Lease.
5.05.2 LANDLORD'S INDEMNITY. Landlord shall indemnify, defend,
protect and hold harmless Tenant (and Tenant's agents, employees, and
contractors) from any and all costs, claims, loss, damage, expense and liability
(including without limitation court costs, litigation expenses, and reasonable
attorneys' fees) incurred in connection with or arising from the following,
except to the extent caused by Tenant's negligence or willful misconduct: (a)
any breach or default in the performance of any obligation of Landlord under
this Lease, (b) any misrepresentation or breach of warranty by Landlord under
this Lease, or (c) any negligence or willful misconduct of Landlord. As material
part of the consideration to Tenant, Landlord assumes all risk of damage to
property or injury to persons in or about the Property arising from any cause
from which Landlord is required to indemnify Tenant pursuant to the foregoing,
and Landlord hereby waives all claims and respect thereof against Tenant, except
to the extent of any claim arising out of the negligence or willful misconduct
of Tenant, its agents, contractors, invitees or permittees. As used in this
Section 5.05, acts and omissions of "Landlord" shall include acts and omissions
of Landlord's employees, agents, contractors and invitees, if applicable. The
provisions of this Section 5.05.2 shall survive the expiration or earlier
termination of this Lease with respect to any claims or liability occurring
prior to such expiration or earlier termination.
Section 5.06. LANDLORD'S ACCESS. Landlord reserves the right at all
reasonable times and upon reasonable notice to Tenant (i.e., notice of not less
than two (2) business days) to enter the Property to (i) inspect it; (ii) show
the Property to prospective purchasers, mortgagees or tenants (but only during
the last year of the Lease Term, in case of prospective tenants, and only if
Landlord will have a residual leasehold interest under the Master Lease at such
time), or to the ground or underlying lessors; (iii) post notices of
non-responsibility if required by statute to be so posted to be effective; (iv)
alter, improve or repair the Property as permitted or required under the terms
of this Lease; or (v) place "For Lease" signs on the Property (but only during
the last year of the Lease Term and only if Landlord will have a residual
leasehold interest under the Master Lease at such time). Any such entries shall
be without the abatement of Rent and shall include the right to take such
reasonable steps as required to accomplish the stated purposes. Any entry into
the Property in the manner described above shall not be deemed to be a forcible
or unlawful entry into, or a detainer of, the Property, or an actual or
constructive eviction of Tenant from any portion of the Property. In case of any
such entry into the Property, Landlord's representatives shall be accompanied by
a representative of Tenant. Landlord acknowledges that the right of Landlord or
any representative of Landlord to enter or have access to Tenant's control room
shall be conditioned upon and subject to Tenant's then security requirements and
procedures, and shall in any event be with the accompaniment of one or more
representatives of Tenant. Tenant represents and warrants that Tenant's present
control room security requirements
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and procedures impose conditions and restrictions but do not prohibit such
access by Landlord or its representatives. Landlord acknowledges the possibility
that such requirements and procedures may in the future prohibit such access,
but Tenant agrees that any such future prohibition will not unfairly
discriminate nor be applied in such a manner so as to unfairly discriminate
against Landlord and its representatives.
Section 5.07 VEHICLE PARKING. Tenant, its permitted Subtenants, and their
employees, contractors, customers and other business invitees shall be entitled
to the exclusive use of those spaces in the vehicle parking areas to be located
on the Property (including the exclusive spaces established by Tenant in the
Common Areas pursuant to Section 4.05(b) above) without paying any Additional
Rent. Tenant shall not allow large trucks or other large vehicles to be parked
on the adjacent public streets.
Section 5.08 QUIET POSSESSION. If Tenant pays the rent and complies with
all other terms of this Lease, Tenant may occupy and enjoy the Property for the
full Lease Term, subject to the provisions of this Lease.
ARTICLE SIX CONDITION OF PROPERTY; MAINTENANCE, REPAIRS AND ALTERATIONS
Section 6.01. CONDITION OF PROPERTY. Landlord warrants that upon
Substantial Completion of the Tenant Improvements, the Building Shell
Improvements and the Tenant Improvements shall have been constructed in a good
and workmanlike manner, in conformance with the plans and specifications
therefor, and shall be free of any defects in workmanship or material and in
conformance with all recorded matters and all Applicable Laws. Except as
expressly provided in this Lease, Tenant acknowledges that neither Landlord nor
any agent of Landlord has made any representation as to the suitability of the
Property for Tenant's intended use. Tenant represents and warrants that Tenant
has made its own inspection of and inquiry regarding the suitability of the
Property (or has had the opportunity to do so) and is not relying on any
representations of Landlord or any Broker with respect thereto. Notwithstanding
the above, Tenant is entitled to the benefit of the construction warranties set
forth in this Section 6.01 and Section 6.03 below.
Section 6.02. EXEMPTION OF LANDLORD FROM LIABILITY. Landlord shall not be
liable for any damage or injury to the person or business (or any loss of income
therefrom), goods, wares, merchandise or other property of Tenant, Tenant's
employees, invitees, customers, or the property of others in the possession and
control of Tenant, in or about the Property, whether such damage or injury is
caused by or results from: (a) fire, steam, electricity, water, gas or rain; (b)
the breakage, leakage, obstruction or other defects of pipes, sprinklers, wires,
appliances, plumbing, air conditioning or lighting fixtures or any other cause;
(c) conditions arising in or about the Property or upon other portions of the
Project, or from other sources or places; or (d) any act or omission of any
other tenant of Landlord. Landlord shall not be liable for any such damage or
injury even though the cause of or the means of repairing such damage or injury
are not accessible to Tenant. The provisions of this Section 6.02 shall not,
however, exempt Landlord from liability to the extent of the negligence or
willful misconduct of Landlord, its agents, contractors, invitees and permitees,
and are subject to Section 4.04(d)(iv) and Section 5.05.2 above.
Section 6.03. LANDLORD'S OBLIGATIONS. Subject to the provisions of Article
Seven (Damage or Destruction) and Article Eight (Condemnation), and except as
provided in Section 4.05 above and in this Section 6.03, Landlord shall have no
responsibility to repair, maintain or replace any portion of the Property. Upon
Substantial Completion of the Tenant Improvements, Landlord shall deliver the
Property to Tenant clean and free of debris, and in conformance with Landlord's
warranties and representations set forth in Section 6.01 above. In the event of
non-compliance with the warranties and representations contained in Section 6.01
above, Landlord shall promptly after receipt of written notice from Tenant
setting forth with specificity the nature and extent of such non-compliance,
rectify the same at Landlord's expense. If Tenant does not give Landlord written
notice of a non-compliance with that warranty within one (1) year after the date
of Substantial Completion of the Building Shell Improvements (with respect to
the Building Shell Improvements) or within one (1) year after the date of
Substantial Completion of the Tenant Improvements (with respect to the Tenant
Improvements), correction of that non-compliance shall be the obligation of
Tenant at Tenant's sole cost and expense, and any further obligation of Landlord
arising from or related to such warranty shall be extinguished except with
respect to any latent defects in those components of the Building for which
Landlord has expressly assumed responsibility below in this Section 6.03.
Landlord shall also obtain a ten (10)-year NDL manufacturer warranty covering
the Building's roof membrane, and shall assign its rights thereunder to Tenant
(and Tenant acknowledges it must assume and comply with all of the obligations
thereunder in connection with such assignment).
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With respect to the Building only, Landlord, at its sole cost and expense,
shall be responsible for repair, maintenance, or replacement (as needed) of the
foundations, structural portions of the roof (but excluding all non-structural
portions such as the roof membrane), exterior walls (but excluding the painting
thereof, which shall be Tenant's sole responsibility) and the floor slab due to
any latent defects therein. Subject to Landlord's one-year warranties set forth
in this Article Six, Landlord shall not be obligated to replace or maintain or
repair windows, doors, plate glass or the interior surfaces of the exterior
walls of the Building, or any of the improvements on the Additional Land or any
of the other Tenant Improvements. Landlord shall not be obligated to undertake
any work pursuant to this Section 6.03 until a reasonable time after receipt of
a written notice from Tenant of the need for such work, and shall diligently
pursue such work until complete. In no event shall normal wear and tear
(including that caused by the elements or other natural environmental
conditions) constitute or be deemed to have caused or resulted in a latent
defect.
Section 6.04. TENANT'S OBLIGATIONS.
(a) Except as otherwise expressly provided in Section 4.05 above,
Section 6.03 above, Article Seven (Damage or Destruction) below, and Article
Eight (Condemnation) below, Tenant, at Tenant's sole cost and expense, shall
keep all portions of the Property (including interior, exterior, systems and
equipment) in good order, condition and repair. If any portion of the Property
or any system or equipment in the Property that Tenant is obligated to repair
cannot be fully repaired or restored, Tenant shall promptly replace such portion
of the Property or system or equipment in the Property. The cost of such
replacement shall be amortized (including Interest) over the useful life as
reasonably determined by Landlord, and Tenant shall only be liable for that
portion of the cost which is applicable to the remaining Lease Term (as it may
be extended), and Landlord shall reimburse Tenant or, at Tenant's option,
provide Tenant with a credit against future Additional Rent obligations in an
amount equal to Landlord's share of such total cost. If any part of the Property
or the Project is damaged by any act or omission of Tenant, to the extent such
damage is not insured under any property insurance policy carried by Landlord
that provides primary coverage, Tenant shall repair or replace the same, as
needed. It is the intention of Landlord and Tenant that, at all times during the
Lease Term, Tenant shall maintain the Property in an attractive, first-class and
fully operative condition. Without limiting the generality of the provisions
contained above in this Section 6.04(a), Tenant agrees to repair any damage to
the Building and Building Premises other than ordinary wear and tear caused by
the transportation and storage of its products in, on, or about the Property,
including, but not limited to any damage to the Building's concrete floor slab,
adjoining concrete ramps, adjoining concrete truck apron, and adjoining asphalt
parking and access areas on the Building Premises due to the use of forklifts
hauling Tenant's products. Tenant's repair obligation described above shall
include the restoration of any damaged areas of the Property or the Project, if
repair is impracticable, so as to restore such areas to the condition existing
prior to such damage. For purposes of the foregoing, "damage" excludes ordinary
wear, tear and scrapes, as well as any settling of concrete and paved areas
reasonably anticipated from Tenant's use of the Property.
Section 6.05. ALTERATIONS, ADDITIONS, AND IMPROVEMENTS.
(a) Any alterations, additions or improvements made to the Building
or the Property by or at the request of Tenant, are herein referred to as
"TENANT'S ALTERATIONS." Tenant shall not make any Tenant's Alterations to the
Building without Landlord's prior written consent, except for non-structural
interior alterations and the initial Tenant Improvements (which are to be
constructed subject to the provisions of Article Fourteen below). Tenant shall
promptly remove any Tenant's Alterations constructed in violation of this
Section 6.05(a) upon Landlord's written request. All Tenant's Alterations shall
be performed in a good and workmanlike manner, in conformity with all Applicable
Laws, and to the extent Landlord's consent is required, using a contractor
reasonably acceptable to Landlord. Upon completion of any such work, Tenant
shall make available for Landlord's review and copying, any "as built" plans,
construction contracts, and proof of payment for labor and materials in Tenant's
possession.
(b) Tenant shall pay when due all claims for labor and material
contracted for by Tenant and furnished to the Property. Tenant shall give
Landlord at least ten (10) days' prior written notice of the commencement of any
work with an anticipated cost of One Hundred Fifty Thousand Dollars
($150,000.00) in Constant Dollars (defined below) or more on the Property (other
than the initial Tenant Improvements), regardless of whether Landlord's consent
to such work is required. Notwithstanding any language to the contrary in this
Section 6.05, with respect to any Tenant's Alterations, regardless of whether
Landlord's consent to such work is
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required under the terms of this Lease, Tenant acknowledges Nevada law may
require Tenant to record a notice of posted security in compliance with the
requirements of Nev. Rev. Stat. Chapter 108 (2005) (the "POSTED SECURITY
REQUIREMENTS"). Concurrently with Landlord's delivery of this Lease to Tenant
for execution, Landlord may elect to provide Tenant with a separate written
notice of the Posted Security Requirements, which shall include an
acknowledgement of Tenant (the "NOTICE AND ACKNOWLEDGEMENT"). If so provided,
Tenant agrees to promptly sign and return the Notice and Acknowledgment to
Landlord; provided, however, that Tenant acknowledges and agrees that under no
circumstances shall such Notice and Acknowledgement or the terms of this Section
6.05 be construed as Landlord's consent to or approval of any Tenant's
Alterations; and provided that the Notice and Acknowledgment shall be in form
reasonably satisfactory to Tenant. Landlord may elect to record and post notices
of non-responsibility on the Property. "CONSTANT DOLLARS" means the value of the
U.S. dollar to which such phrase refers, as adjusted from time to time. An
adjustment shall occur on the first (1st) day of January of the sixth (6th) full
calendar year following the date of this Lease, and thereafter at five (5) year
intervals. Constant Dollars shall be determined by multiplying the dollar amount
to be adjusted by a fraction, the numerator of which is the Current Index Number
and the denominator of which is the Base Index Number. The "Base Index Number"
shall be the level of the Index for the calendar month during which this
Declaration is recorded in the Official Records; the "Current Index Number"
shall be the level of the Index for the calendar month that corresponds to the
month of the date of this Lease of the year preceding the adjustment year; the
"Index" shall be the Consumer Price Index for All Urban Consumers, published by
the Bureau of Labor Statistics of the United States Department of Labor for U.S.
City Average, All Items (1996=100), or any successor index thereto as
hereinafter provided. If publication of the Index is discontinued, or if the
basis of calculating the Index is materially changed, then Landlord shall
substitute for the Index comparable statistics as computed by an agency of the
United States Government or, if none, by a substantial and responsible
periodical or publication of recognized authority most closely approximating the
result which would have been achieved by the Index.
(c) To the extent Landlord's prior consent is required by this
Section 6.05, Landlord may condition its consent to any proposed Tenant's
Alterations on: (i) Tenant's submission to Landlord, for Landlord's prior
written approval, of all plans and specifications relating to Tenant's
Alterations; (ii) Tenant's written notice of whether Tenant's Alterations
include the use or handling of any Hazardous Materials; (iii) Tenant's
obtaining, for Landlord's benefit and protection, of such insurance as Landlord
may reasonably require (in addition to that required under Section 4.04 of this
Lease); (iv) Tenant's compliance with the requirements of Nev. Rev. Stat.
Chapter 108 (2005) or any applicable successor statute; and (v) Tenant's payment
to Landlord of all reasonable costs and expenses incurred by Landlord because of
Tenant's Alterations other than the initial Tenant Improvements, including
without limitation, costs incurred in reviewing the plans and specifications
for, and inspecting the progress of, Tenant's Alterations; provided, however,
that Landlord shall only be entitled to such payment to the extent such work
affects (i) the drainage or grade of the Property, or (ii) structural components
(including the floor slabs) of any improvements on the Building Premises. Such
reasonable cost and expenses shall include the standard hourly charges incurred
by Landlord when using employees of Commerce Construction Co., L.P. ("LANDLORD'S
CONTRACTOR") for such review and inspection.
(d) Upon imposition of any lien resulting from construction of
Tenant's Alterations contracted for by Tenant (an "IMPOSITION"), Tenant shall
either (i) cause the same to be released, if recorded, or (ii) diligently
contest such Imposition and indemnify, defend, and hold Landlord harmless from
any and all loss, cost, damage, liability and expense (including attorney's
fees) arising from or related to it; provided, however, that consistent with
Article Seventeen below, if the Master Landlord requires the removal of any such
Imposition, Tenant shall comply with the terms of the Master Lease and either
bond against or discharge the same within the time period provided in the Master
Lease. Notwithstanding the above, in case of an Imposition for the claimed cost
of work, materials or equipment furnished in construction of the Tenant
Improvements by Landlord pursuant to Section 14.02 below, the provisions of this
Section 6.05(d) shall not apply, unless at the time or recording of the
Imposition (i) all of that claimed cost has been approved by Tenant's Architect
for payment as provided in Section 14.02(a) below and (ii) twenty (20) days or
more have expired following that approval without payment by Tenant to Landlord
as provided in Section 14.02 below.
(e) Notwithstanding any language to the contrary in this Section
6.05, if the proposed Tenant's Alterations (other than the Tenant Improvements,
which are to be constructed subject to the provisions of Article Fourteen
below), materially affect one or more of the structural components of the
Building, or life safety
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matters, including, but not limited to, the Building's or Project's fire
suppression system, Landlord's prior written consent will be required.
(f) Tenant acknowledges and agrees that any Tenant's Alterations are
wholly optional with Tenant and are not being required by Landlord, either as a
condition to the effectiveness of this Lease or otherwise.
Section 6.06. CONDITION UPON TERMINATION. Subject to the provisions
of Article Seven and Article Eight below, upon the termination of this Lease,
Tenant shall surrender the Property to Landlord, broom clean and in good
condition and repair, ordinary wear and tear excepted; provided, however, Tenant
shall not be obligated to repair any damage which Landlord is required to repair
under Article Seven (Damage or Destruction) below, if any, or make any repairs
for which Landlord is responsible hereunder. Landlord may require Tenant to
remove any Tenant's Alterations (whether or not made with Landlord's consent)
prior to, or within thirty (30) days after, the expiration of this Lease and to
restore the Building to its prior condition at Tenant's expense; provided,
however, that Tenant shall not have any obligation to remove any Building Shell
Improvements or Tenant Improvements save and except those described on Exhibit
"J" attached hereto and by this reference incorporated herein, and then only if
requested by Landlord to do so at least one hundred eighty (180) days prior to
the expiration or earlier termination of this Lease (or such shortened period if
the 180-day notice is not practicable under the circumstances, such as in case
of an early termination based on an Event of Default). All alterations,
additions and improvements which Tenant does not remove shall become Landlord's
property if surrendered to Landlord upon the expiration or earlier termination
of this Lease. Tenant may remove any of Tenant's machinery, equipment (including
Tenant's Telecommunication Equipment), trade fixtures and other personal
property. Tenant shall repair, at Tenant's expense, any damage to the Building
or Building Premises caused by the removal of any such machinery, equipment,
fixtures or personal property (including, without limitation, the complete
removal of all studs and bolts that penetrate the floor or walls and filling and
patching the holes). In no event, however, shall Tenant remove any of the
following materials or equipment (which shall be deemed Landlord's property)
from the Building or Building Premises without Landlord's prior written consent:
any power wiring and power panels; lighting and lighting fixtures; wall
coverings; drapes, blinds and other window coverings; carpets and other floor
coverings; heaters, air conditioners and any other heating and air conditioning
equipment; fencing and security gates; load levelers, dock lights, dock locks
and dock seals; and other similar building operating equipment and decorations.
Tenant's obligations under this Section 6.06 shall also include its obligations
under Section 5.04 with respect to any Sign.
ARTICLE SEVEN DAMAGE OR DESTRUCTION
Section 7.01. DAMAGE OR DESTRUCTION TO PROPERTY.
(a) In case of damage to or destruction of Building Shell
Improvements other than the ESFR System, or any part of those Building Shell
Improvements by fire or other casualty, Tenant will promptly give written notice
thereof to Landlord and shall, in accordance with the provisions of this Article
and all other provisions of this Lease, commence and complete restoration of the
Base Building Shell Improvements and Common Area Improvements on the Building
Premises (other than the ESFR System) in conformance with the Base Building
Shell Plans together with such Building Modifications as Tenant elects to
restore and such Tenant Improvements and other Tenant's Alterations as Tenant
elects to restore. In any such event, Tenant shall also have the right to make
additional alterations in conformity with and subject to the conditions of
Section 6.05 above, and in conformity with the plans and specifications required
to be prepared pursuant to this Section 7.01. Tenant's obligations in this
Section 7.01(a) shall be effective whether or not (i) such damage or destruction
has been insured or was insurable, (ii) Tenant is entitled to receive any
insurance proceeds, or (iii) insurance proceeds are sufficient to pay in full
the cost of the restoration work in connection with such restoration. Such
restoration shall be commenced promptly and shall be prosecuted and completed
expeditiously, Force Majeure Delays excepted. Landlord, its agents and
mortgagees, may, from time to time, inspect the restoration upon reasonable
advance notice to Tenant during normal business hours, subject to the provisions
of Section 5.06 above. In case of damage to or destruction of the ESFR System,
other Common Area Improvements not located on the Building Premises, or any part
thereof by fire or other casualty, Landlord shall promptly commence and shall
expeditiously prosecute and complete the restoration thereof, Force Majeure
Delays, excepted. Any restoration or rebuilding of the Building shall be in
conformance with such building code and other Applicable Law requirements as
shall permit the issuance of a certificate of occupancy for the restored or
reconstructed Building by Clark County, Nevada, or such other governmental
entity as shall have jurisdiction with respect thereto.
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(b) In the event of any damage or destruction of the Base Building
Shell Improvements, or any substantial part thereof by fire or other casualty,
if the anticipated cost of repair exceeds One Hundred Fifty Thousand Dollars
($150,000.00) in Constant Dollars, Tenant agrees to furnish to Landlord at least
ten (10) days before the commencement of the restoration of such damage or
destruction, the following:
(i) Complete plans and specifications for such restoration
prepared by a licensed and reputable architect (the "ARCHITECT"), which plans
and specifications shall meet with the reasonable approval of Landlord, and
Landlord's mortgage lender, together with the approval thereof by all
governmental authorities then exercising jurisdiction with regard to such work.
(ii) Contracts then customary in the trade with (a) the
Architect, and (b) with a reputable and responsible contractor providing for the
completion of such restoration in accordance with said plans and specifications.
(iii) Certificates of insurance required by this Lease.
(c) All insurance claims shall be adjusted as provided in Section
4.04(d)(ix) above, and insurance proceeds shall be applied to the payment of the
cost of the restoration, including the cost of temporary repairs or for the
protection of the Property pending the completion of permanent restoration (all
of which temporary repairs, protection of the Property and permanent restoration
are hereinafter collectively referred to as the "RESTORATION"), from time to
time as such Restoration progresses. Insurance proceeds for the Base Building
Shall Improvements shall be received by Tenant in trust for the purposes of
paying the cost of Restoration of Base Building Shell Improvements.
(d) If the net insurance proceeds shall be insufficient to pay the
entire cost of such Restoration, Tenant will pay the deficiency.
(e) If the Property shall be partially or totally damaged or
destroyed by fire or other casualty, except as provided in paragraph (f) below,
Tenant shall restore such damage or destruction as previously provided in this
Section 7.01, Base Rent and Additional Rent shall continue to be due and payable
as if no damage or destruction had occurred, and this Lease shall remain in full
force and effect. In no event shall Base Rent or Additional Rent abate, nor
shall this Lease terminate (subject to paragraph (f) below) by reason of such
damage or destruction.
(f) Notwithstanding anything in this Lease to the contrary, in case
of damage to or destruction of Building during the last year of the Lease Term
(including the last year of any previously exercised Lease Term Extension), and
if such damage will require more than one hundred twenty (120) days to
substantially complete the repair, then Tenant shall have the right and option
to terminate this Lease upon written notice to Landlord dispatched within ninety
(90) days after such damage or destruction. In such event, Tenant shall have the
right and option to do either of the following: (i) commence and complete
restoration of the Base Building Shell Improvements together with such Building
Modifications as Tenant elects to restore and such Tenant Improvements and other
Tenant's Alterations as Tenant elects to restore, or (ii) demolish and remove
the Building and pay to Landlord the full replacement cost of the Base Building
Shell Improvements (including any sums necessary to replace the Base Building
Shell Improvements in conformance with such building code and other Applicable
Law requirements as shall permit the issuance of a certificate of occupancy for
the replaced Building), and this Lease shall terminate upon such restoration or
upon such demolition and payment. Any Restoration or rebuilding of the Building
shall be in conformance with such building code and other Applicable Law
requirements as shall permit the issuance of a certificate of occupancy for the
restored or reconstructed Building by Clark County, Nevada or such other
governmental entity as shall have jurisdiction with respect thereto.
Section 7.02. WAIVER. Tenant waives the protection of any statute,
code or judicial decision which may grant to Tenant the right to terminate a
lease in the event of the destruction of the leased property. Tenant agrees that
the provisions of Article Seven above shall govern the rights and obligations of
Landlord and Tenant in the event of any destruction to the Property.
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ARTICLE EIGHT CONDEMNATION
If all or any portion of the Property is taken under the power of
eminent domain or sold under the threat of that power (all of which are called
"CONDEMNATION"), this Lease shall terminate as to the part taken or sold on the
date the condemning authority takes title or possession, whichever occurs first.
If a Condemnation occurs (i) through which any material portion of the Building
is taken or (ii) through which one acre or more of Property land is taken or one
acre or more of Property land will have been cumulatively taken through that
Condemnation and any prior Condemnation, or (iii) through which Property land is
taken after more than one acre of Property land has already been taken through
prior Condemnation, then Tenant may terminate this Lease as of the date the
condemning authority takes title or possession, by delivering written notice to
Landlord, within ninety (90) days after the condemning authority takes title or
possession. If Tenant does not terminate this Lease, this Lease shall remain in
effect as to the portion of the Property not taken, except that the Base Rent
and Additional Rent shall be reduced equitably in the same proportion that the
value of the Property taken bears to the value of the Property prior to such
Condemnation. If Landlord and Tenant are unable to agree upon the amount of such
reduction, the values shall be determined by process of appraisal, in the same
manner set forth in Section 2.05(d) above for determining fair rental value. If
this Lease is not terminated, Tenant shall repair any damage to the Building
Shell Improvements and Common Area Improvements on the Building Premises other
than the ESFR System, and Landlord shall repair any damage to the ESFR System
and the Common Area Improvements not located on the Building Premises. If the
damages received by Tenant are not sufficient to pay for repairs to be made by
Tenant, Tenant shall pay any amount in excess of such award necessary to
complete such repair. Tenant shall be entitled to all of any award or payment
made for (i) any such repair or restoration to be made by Tenant, (ii) the
Building Modifications, (iii) Tenant Improvements and (iv) any other Tenant
Alterations, including buildings and other real property improvements on the
Additional Land, and Landlord hereby assigns to Tenant any interest in any such
awards or payments. Landlord shall be entitled to all of any award or payment
made for Common Area Improvements and Base Building Shell Improvements (save and
except any award or payment to be made to Tenant for repair or restoration of
Common Area Improvements or the Building), and Tenant hereby assigns to Landlord
any interest in any such awards or payments. Landlord and Tenant shall be
entitled to assert and make claim for any other award or payment in connection
with any Condemnation, according to their respective interests in the Property.
Landlord's mortgage lender shall also be permitted to participate in any such
proceeding.
ARTICLE NINE ASSIGNMENT AND SUBLETTING
Section 9.01. TRANSFERS. Subject to all of the terms of this Article
Nine, Tenant shall not, without the prior written consent of Landlord, assign,
mortgage, pledge, encumber or otherwise transfer, this Lease or any interest
hereunder, permit any assignment or other such foregoing transfer of this Lease
or any interest hereunder by operation of law, or sublet the Property or any
part thereof (all of the foregoing are hereinafter sometimes referred to
collectively as "TRANSFERS" and any person to whom any Transfer is made or
sought to be made is hereinafter sometimes referred to as a "TRANSFEREE"). To
request Landlord's consent to any Transfer requiring such consent under the
provisions of this Article Nine, Tenant shall notify Landlord in writing, which
notice (the "TRANSFER NOTICE") shall include (i) the proposed effective date of
the Transfer, which shall not be less than forty-five (45) days after the date
of delivery of the Transfer Notice, (ii) a description of the portion of the
Property to be transferred (the "SUBJECT SPACE"), (iii) all of the terms of the
proposed Transfer and the consideration therefor, including a calculation of the
Transfer Premium (defined below) in connection with such Transfer (if
applicable), the name and address of the proposed Transferee, and a copy of all
existing documentation pertaining to the proposed Transfer, including all
existing operative documents to be executed to evidence such Transfer or the
agreements incidental or related to such Transfer, and (iv) current financial
statements of the proposed Transferee certified by an officer, partner or owner
thereof, and any other information reasonably required by Landlord, which will
enable Landlord to determine the financial responsibility, character, and
reputation of the proposed Transferee, nature of such Transferee's business and
proposed use of the Subject Space, and such other information as Landlord may
reasonably require. Any Transfer requiring but made without Landlord's prior
written consent shall, at Landlord's option, be null, void and of no effect, and
if not terminated and rescinded upon expiration of the notice and cure periods
in Section 10.02 (c), shall, at Landlord's option, constitute a material default
by Tenant under this Lease.
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Section 9.02. LANDLORD'S CONSENT. Landlord shall not unreasonably
withhold its consent to any proposed Transfer of the Subject Space to the
Transferee on the terms specified in the Transfer Notice. The parties hereby
agree that it shall be reasonable under this Lease and under any applicable law
for Landlord to withhold consent to any proposed Transfer where one or more of
the following apply, without limitation as to other reasonable grounds for
withholding consent:
9.02.1 The Transferee's business or use of the Subject Space is not
permitted under this Lease and Landlord decides, upon the exercise of its
reasonable discretion, not to approve such new use;
9.02.2 Any proposed assignee Transferee is not a party of reasonable
financial worth and/or financial stability in light of the responsibilities
involved under this Lease on the date consent is requested; or
9.02.3 The proposed Transfer would cause Landlord to be in violation
of another lease or agreement to which Landlord is a party.
If Landlord consents to any Transfer pursuant to the terms of this
Section 9.02), Tenant may within one year after Landlord's consent, but not
later than the expiration of such year period, enter into such Transfer of the
Property or portion thereof, upon substantially the same terms and conditions as
are set forth in the Transfer Notice furnished by Tenant to Landlord pursuant to
Section 9.01 of this Lease.
Section 9.03. TRANSFER PREMIUM. During any Extension (but not during
the initial Lease Term), in the event of a Transfer of Subject Space consisting
of warehouse area on the ground floor of the Building, and if the Transfer
requires Landlord's consent, if Landlord consents to such a Transfer, as a
condition thereto which the parties hereby agree is reasonable, Tenant shall pay
to Landlord fifty percent (50%) of any "TRANSFER PREMIUM," as that term is
defined in this Section 9.03, received by Tenant from such Transferee, as
received by Tenant from the Transferee. "Transfer Premium" shall mean all rent,
additional rent or other consideration payable by such Transferee for the ground
floor warehouse area in excess of the Rent payable by Tenant under this Lease
for the area on a per rentable square foot basis if less than all of the
Building is transferred, less the total of actual and reasonable expenses
incurred by Tenant in connection with such Transfer (e.g., tenant improvement
costs, legal fees, leasing commission, etc., if applicable). All of the
foregoing sums shall be offset against first due Transfer Premium payments
otherwise payable to Landlord. "Transfer Premium" shall also include, but not be
limited to, key money and bonus money paid by Transferee to Tenant in connection
with such Transfer, and any payment in excess of fair market value for services
rendered by Tenant to Transferee or for assets, fixtures, inventory, equipment,
or furniture transferred by Tenant to Transferee in connection with such
Transfer. Notwithstanding any language to the contrary in this Section 9.03,
Tenant shall not be responsible for payment of any Transfer Premium otherwise
payable in connection with a subletting by the original Tenant of up to fifty
thousand (50,000) square feet of ground floor warehouse area in the Building.
Section 9.04. TRANSFER INVOLVING A PERMITTED USE. Notwithstanding
anything to the contrary contained in Section 9.01 above, a Transfer by the
original Tenant or a Tenant Affiliate of the original Tenant of a portion of the
Building to a subtenant for a Permitted Use shall not be deemed a Transfer for
which Landlord's consent is required. Further, notwithstanding anything to the
contrary contained in Section 9.01 above, a Transfer by the original Tenant to a
Tenant Affiliate of the original Tenant of a portion of the Property other than
the Building to a subtenant for a Permitted Use shall not be deemed a Transfer
for which Landlord's consent is required if (i) the Transfer includes an area of
the Building Premises or Additional Land incident to, ancillary to, and as a
part of a Transfer of a portion of the Building, (ii) the Transferee is a
vendor, supplier, contractor or co-venturer of Tenant, or (iii) the Permitted
Uses for which the Subject Space may be utilized by the Transferee are uses
relating to or in support of Tenant's activities as a public utility. Tenant
shall promptly notify Landlord of any such Transfer and promptly supply Landlord
with any documents or information reasonably requested by Landlord regarding
such Transfer. Any such sublease shall still comply with the provisions of
Section 9.08 below. Notwithstanding the foregoing provisions of this Section
9.04, any sublease of a portion of the Property for any use which (i) is a
Permitted Use, but which would create an unusual or atypical wear and tear on
the Building, different in nature and degree from that which results from the
original Tenant's use of the Property, (ii) is a Permitted Use, but which would
involve the use, handling, storage or disposal of material amounts of Hazardous
Materials other than those which are the same or similar to those used by the
original Tenant and in quantities and processes similar to the original Tenant's
uses, or (iii) is not a Permitted Use, shall require the prior written consent
of Landlord.
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Section 9.05. EFFECT OF TRANSFER. If Landlord consents to a
Transfer, (i) the terms and conditions of this Lease shall in no way be deemed
to have been waived or modified, (ii) such consent shall not be deemed consent
to any further Transfer by either Tenant or a Transferee, (iii) Tenant shall
deliver to Landlord, promptly after execution, a copy of executed Transfer
documentation pertaining to the Transfer, (iv) Tenant shall furnish upon
Landlord's request a complete statement certified by an independent certified
public accountant, or Tenant's chief financial officer, setting forth in detail
the computation of any Transfer Premium Tenant has derived and shall derive from
such Transfer (if applicable), and (v) no Transfer relating to this Lease or
agreement entered into with respect thereto, whether with or without Landlord's
consent, shall relieve Tenant or any guarantor (if applicable) of Tenant's
obligations under this Lease from liability under this Lease. Landlord or its
authorized representatives shall have the right at all reasonable times to audit
the books, records and papers of Tenant relating to any Transfer Premium, and
shall have the right to make copies thereof. If the Transfer Premium respecting
any Transfer shall be found understated, Tenant shall, within thirty (30) days
after demand, pay the deficiency and the reasonable costs of such audit.
Section 9.06. INTENTIONALLY OMITTED.
Section 9.07. TENANT AFFILIATE. Notwithstanding anything to the
contrary contained in Section 9.01 above, a Transfer of all or a portion of the
Property or any interest of Tenant in this Lease to a Tenant Affiliate (as
defined below), shall not be deemed a Transfer under this Article Nine for which
consent is required provided that (i) if such Transfer is an assignment, the
Tenant Affiliate assumes in writing all of Tenant's obligations under this
Lease; and (ii) such Transfer is not a subterfuge by Tenant to avoid its
obligations under this Lease. Tenant shall promptly notify Landlord of any such
transfer and promptly supply Landlord with copies of any applicable documents of
transfer regarding such Transfer. For purposes of this Lease, a "TENANT
AFFILIATE" means (i) an entity which is controlled by, controls, or is under
common control with Tenant, (ii) an entity resulting from a merger of,
consolidation with, or reorganization of Tenant or (iii) a Permitted Purchaser
(as defined below). "CONTROL," as used herein, shall mean the ownership,
directly or indirectly, of at least twenty percent (20%) of the voting
securities of, or possession of the right to vote, in the ordinary direction of
its affairs, of at least twenty percent (20%) of the voting interest in, any
person or entity. Tenant may assign this Lease, without Landlord's consent, to
any entity to which all or substantially all of Tenant's assets are sold, so
long as (a) such purchaser has a tangible net worth (as determined according to
GAAP then in effect) equal to or greater than One Hundred Million Dollars
($100,000,000.00), and (b) Tenant complies with the requirements stated above in
this Section 9.07 with respect to a Transfer involving a Tenant Affiliate. The
original Tenant may also assign this Lease, without Landlord's consent, to any
entity to which other material assets of the original Tenant are sold, so long
as (a) such purchaser has a tangible net worth (as determined according to GAAP
then in effect) equal to or greater than One Hundred Million Dollars
($100,000,000.00), (b) Tenant complies with the requirements stated above in
this Section 9.07 with respect to a Transfer involving a Tenant Affiliate and
(c) the original Tenant remains liable for its obligations under this Lease as
provided in Section 9.05. An assignee described in either of the two immediately
preceding sentences is a "PERMITTED PURCHASER."
Section 9.08. TRANSFER INVOLVING SUBLEASE. Every approved sublease
transaction shall be evidenced by a written sublease (the "SUBLEASE") between
Tenant and the subtenant (the "SUBTENANT"). The Sublease or, where applicable,
Landlord's written consent required under Section 9.01 above, to which Tenant
and Subtenant shall be parties (the "CONSENT"), shall comply with the following
requirements:
(i) The Sublease shall be subject to, and shall incorporate by
reference, all of the terms and conditions of this Lease, except those terms and
conditions relating to Base Rent, Additional Rent, and any other amount due
under this Lease. Subtenant shall acknowledge in the Sublease or Consent that it
has reviewed and agreed to all of the terms and conditions of this Lease.
Subtenant shall agree in the Sublease or Consent not to do, or fail to do,
anything that would cause Tenant to violate any of its obligations under this
Lease.
(ii) The Sublease or Consent shall contain, in full, any use
restrictions or other provisions of this Lease that affect the use of the
Property.
(iii) The Sublease or Consent shall contain a waiver of subrogation
against Landlord, and any Consent shall contain a waiver of subrogation by
Landlord against Subtenant.
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(iv) The Sublease or Consent shall prohibit a sub-subletting of the
Property or the assignment of the Sublease by Subtenant, without first obtaining
Landlord's consent if Landlord's consent to the Sublease was required in this
Lease.
(v) The Sublease or Consent shall require Subtenant, acting through
Tenant, to obtain Landlord's prior written consent to any alterations to the
Property, to the extent Tenant is required by this Lease to obtain such consent.
(vi) The Sublease or Consent shall provide that, at Landlord's
option, the Sublease shall not terminate in the event that this Lease
terminates. The Sublease shall require Subtenant to execute an attornment
agreement, if Landlord, in its sole and absolute discretion, shall elect to have
the Sublease continue beyond the date of termination of this Lease. Such
attornment agreement shall provide that Subtenant confirms it is in direct
privity of contract with Landlord and that all obligations owed to Tenant under
the Sublease shall become obligations owed to Landlord for the balance of the
term of the Sublease.
(vii) The Sublease or Consent shall provide that unless and until
such time as an attornment agreement is executed by Subtenant pursuant to the
terms and conditions of the preceding subsection (vi), nothing contained in the
Sublease shall create or shall be construed or deemed to create privity of
contract or privity of estate between Landlord and Subtenant.
(viii) The Sublease or Consent shall provide that Subtenant shall
have no right (and shall waive any rights it may have) under the Sublease to
hold Landlord responsible for any liability in connection with the Property,
including, without limitation, any liability arising from the noncompliance with
any federal, state, or local laws applicable to the Property.
(ix) The Sublease or Consent shall provide that nothing in the
Sublease shall amend or shall be construed or deemed to amend this Lease.
SECTION 9.09. NO MERGER. No merger shall result from Tenant's sublease of
the Property under this Article Nine, Tenant's surrender of this Lease or the
termination of this Lease in any other manner. In any such event, Landlord may
terminate any or all subtenancies or succeed to the interest of Tenant as
sublandlord under any or all subtenancies.
Section 9.10. RIGHT TO MORTGAGE LEASEHOLD INTEREST. Notwithstanding any
language to the contrary in this Article Nine, Tenant and any Tenant Affiliate,
shall have the right, from time to time, without Landlord's prior written
consent or approval, to mortgage and encumber Tenant's interest in this Lease
and its leasehold interest in the Property. Any such leasehold mortgage is
herein referred to as a "Leasehold Mortgage" or "permitted Leasehold Mortgage"
As used in this Section and throughout this Lease, the noun "mortgage" shall
include a deed of trust or other security instrument (whether in the nature of a
security agreement, assignment, collateral assignment or otherwise); the verb
"mortgage" shall include the granting or creation of a deed of trust or other
such security instrument; the word "mortgagee" shall include the beneficiary
under a deed of trust or other such secured party or assignee; and the phrase
"Leasehold Mortgagee" or "permitted Leasehold Mortgagee" shall mean a mortgagee
of or with respect to a Leasehold Mortgage.
Section 9.11. RIGHT TO NOTICES. If Tenant shall mortgage this Lease in
accordance with Section 9.10 above and shall have furnished Landlord the name
and mailing address of the Leasehold Mortgagee, then Landlord shall give such
Leasehold Mortgagee, at the address specified by Tenant (as the same may be
changed, from time to time, by Tenant or such Leasehold Mortgagee by notice
given Landlord in conformance with Section 16.06 below and in the manner
required by Section 16.06 below), duplicate copies of all notices to Tenant and
all documents and suits delivered to or served upon Tenant, and notwithstanding
anything in this Lease to the contrary, no notice intended for Tenant shall be
deemed properly given, and no Event of Default hereunder shall be deemed to have
occurred unless Landlord shall have given the Leasehold Mortgagee a copy of its
notices to Tenant relating to such Event of Default. Further, notwithstanding
anything in this Lease to the contrary, no Event of Default shall have occurred,
Landlord shall not be empowered to terminate this Lease and this Lease shall not
expire by reason of the occurrence of any Event of Default hereunder unless
Tenant's applicable cure period with respect to such Event of Default shall have
expired without cure or commencement of cure as provided in Section 10.02, and
an additional
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fifteen (15) business days shall have expired without cure or a failure of
performance following receipt by the Leasehold Mortgagee entitled to notice
under the provisions of this Section of written notice from Landlord specifying
(i) the nature of the potential Event of Default, (ii) this Lease Section
together with the Lease Section requiring the applicable performance, (iii) that
the applicable period for Tenant's cure or commencement of cure has expired
without cure or commencement of cure by Tenant and (iv) that unless the
Leasehold Mortgagee cures or commences cure within fifteen (15) business days of
receipt of the notice an Event of Default shall occur and all applicable cure
periods shall have expired.
Section 9.12. RIGHT TO CURE. Notwithstanding anything in this Lease to the
contrary, a Leasehold Mortgagee shall have the right to pay any amount or do any
act or thing required of Tenant and so remedy any default under this Lease or
cause the same to be remedied, and Landlord shall accept such performance by or
at the instance of such Leasehold Mortgagee as if made by Tenant.
Section 9.13. ASSUMPTION OF OBLIGATIONS. Notwithstanding anything in this
Lease to the contrary, a Leasehold Mortgagee or the purchaser at any foreclosure
or similar sale, without the necessity of Landlord's prior approval, shall
become the legal owner and holder of Tenant's leasehold estate under this Lease
upon lawful foreclosure of a Leasehold Mortgage or as a result of the assignment
of Tenant's leasehold estate under this Lease in lieu of foreclosure, becoming
thereby subject to all the terms and conditions of this Lease. Except as
otherwise permitted in the following sentence of this Section, upon so becoming
the owner and holder of the leasehold estate, a Leasehold Mortgagee or the
purchaser at any foreclosure or similar sale shall have all rights, privileges,
obligations and liabilities of the original Tenant. Notwithstanding anything in
this Lease to the contrary, a Leasehold Mortgagee or the purchaser at any
foreclosure or similar sale following lawful foreclosure of a Leasehold Mortgage
or the assignment of Tenant's leasehold estate under this Lease in lieu of
foreclosure shall have the right to thereupon and thereafter assign Tenant's
leasehold estate under this Lease, without the prior written consent of
Landlord. In the event of any such assignment, the assignee shall become Tenant
hereunder, and the assigning Leasehold Mortgagee or purchaser shall thereupon be
relieved and released of any liability or obligation under this Lease accruing
after the effective date of such assignment. Any Leasehold Mortgage may provide,
at Tenant's option, that the mortgagee, upon making good any default or defaults
on the part of Tenant, shall be thereby subrogated to any and all of the right
of Tenant under the terms and provisions of this Lease.
Section 9.14. OTHER PROVISIONS. For the benefit of any Leasehold
Mortgagee, Landlord shall not accept a voluntary surrender of this Lease at any
time while a Leasehold Mortgage shall remain a lien on the leasehold interest of
Tenant without obtaining the prior written approval of the Leasehold Mortgagee.
ARTICLE TEN DEFAULTS; REMEDIES
Section 10.01. COVENANTS AND CONDITIONS. Tenant's performance of each of
Tenant's obligations under this Lease is a condition as well as a covenant.
Tenant's right to continue in possession of the Property is conditioned upon
such performance. Time is of the essence in the performance of all covenants and
conditions of Landlord and Tenant in this Lease.
Section 10.02. DEFAULTS. Tenant shall be in material default under this
Lease (an "Event of Default"):
(a) If Tenant's vacation of the Property results in the cancellation
of any insurance required in Section 4.04(b) above and Tenant does not replace
such insurance at its cost, or agree to self-insure with respect to such
insurance as provided in Section 4.04(e) within thirty (30) days of receipt of
written notice from Landlord that such insurance is being cancelled or has been
cancelled, demanding such replacement or self-insurance;
(b) If Tenant fails to pay rent or any other charge when due and
such failure continues for a period of fifteen (15) business days or more
following Tenant's receipt of written notice thereof from Landlord demanding
payment;
(c) If Tenant fails to perform any of Tenant's material non-monetary
obligations under this Lease or is otherwise in material breach of its
obligations under this Lease for a period of thirty (30) days after written
notice from Landlord; provided that if more than thirty (30) days are required
to complete such performance or cure such breach, Tenant shall not be in default
if Tenant commences such performance or cure within the thirty
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(30) day period and thereafter diligently pursues its completion. The notice
required by this paragraph is (i) intended to satisfy any and all notice
requirements imposed by law on Landlord and is not in addition to any such
requirement, and (ii) not intended to extend the time for Tenant's performance
if a shorter period of time for performance is expressly provided in this Lease
(although Tenant shall not be in material default of this Lease unless and until
that (a) shorter period of time for performance expires without performance, (b)
Landlord thereupon or thereafter provides the 30-day written notice provided for
above and (c) Tenant fails to complete such performance or cure such breach
within the time period set forth above in this Section 10.02(c)).
(d) If Tenant's interest in this Lease is sold, transferred or
conveyed after attachment, execution or other judicial seizure by a party other
than a permitted Leasehold Mortgagee and is not redeemed by Tenant prior to
expiration of any period during which Tenant may lawfully do so.
SECTION 10.03. REMEDIES. On the occurrence of any Event of Default,
Landlord may, at any time thereafter, with or without notice or demand (except
as required in Section 9.11 above, and except with respect to Tenant or a Tenant
Affiliate) and without limiting Landlord in the exercise of any right or remedy
which Landlord may have:
(a) Terminate Tenant's right to possession of the Property through
the institution of restitution, unlawful detainer or other legal action (as
respects the original Tenant or any Tenant Affiliate of the original Tenant) or
by any other lawful means (as respects a Tenant other than the original Tenant
or any Tenant Affiliate of the original Tenant). Upon termination of Tenant's
possession and occupancy of the Property and recovery, occupancy and possession
of the Property by Landlord, this Lease shall terminate. In such event, Landlord
shall be entitled to recover from Tenant all compensatory damages reasonably
incurred by Landlord by reason of Tenant's default. If Tenant has vacated the
Property, Landlord shall have the option of (i) retaking possession of the
Property as provided in this Section 10.03(a) or (ii) proceeding under Section
10.03(b) below;
(b) Maintain Tenant's right to possession, in which case this Lease
shall continue in effect whether or not Tenant has abandoned the Property. In
such event, Landlord shall be entitled to enforce all of Landlord's rights and
remedies under this Lease, including the right to recover the rent as it becomes
due; or
(c) Pursue any other remedy now or hereafter available to Landlord
under the laws or judicial decisions of the State of Nevada not expressly
prohibited in this Lease.
Notwithstanding any language to the contrary in this Section 10.03, Landlord
agrees to use commercially reasonable efforts to relet the Property and take
other commercially reasonable action in mitigation of damages caused by Tenant's
default hereunder. The provisions of this Section 10.03 shall survive
termination of the Lease.
Section 10.04. TERMINATION. If Landlord elects to terminate this
Lease as a result of a Tenant default, Tenant shall be liable to Landlord for
all compensatory damages resulting therefrom, which shall include, without
limitation, all costs, expenses and fees, including reasonable attorneys' fees
that Landlord reasonably incurs in connection with the filing, commencement,
pursuing and/or defending of any action in any bankruptcy court or other court
with respect to this Lease; the obtaining of relief from any stay in bankruptcy
restraining any action to evict Tenant; or the pursuing of any action with
respect to Landlord's right to possession of the Property. All such damages
suffered (apart from Base Rent and other rent payable hereunder) shall
constitute pecuniary damages that must be reimbursed to Landlord prior to
assumption of this Lease by Tenant or any successor to Tenant in any bankruptcy
or other proceeding.
Section 10.05. CUMULATIVE REMEDIES. Exercise of any right or remedy shall
not prevent a party from exercising any other right or remedy not expressly
prohibited in this Lease.
Section 10.06. SURRENDER. No act or thing done by Landlord or its agents
during the Lease Term shall be deemed an acceptance of a surrender of the
Property, and no agreement to accept a surrender of the Property shall be valid
unless made in writing and signed by Landlord.
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Section 10.07. REMOVAL OF TENANT'S PROPERTY. All furniture, equipment, and
other personal property of Tenant not removed from the Property upon the
vacation thereof following an uncured default by Tenant or upon the termination
of this Lease for any cause whatsoever shall be deemed to have been abandoned by
Tenant, and may be appropriated, sold, stored, destroyed or otherwise disposed
of by Landlord without obligation to account therefor if Landlord first gives
thirty (30) days' written notice to Tenant that Landlord intends to so
appropriate, sell, store, destroy or otherwise dispose of such furniture,
equipment and other personal property, unless Tenant retrieves such property
within such 30-day period, which Landlord shall permit Tenant to do during
reasonable times following dispatch of such notice. Tenant shall reimburse
Landlord for all reasonable expenses incurred in connection with such
disposition of such personal property. Landlord, upon presentation of reasonable
evidence of a third party's claim of ownership or security interest in any such
abandoned property, may turn over such property to the third party claimant
without any liability to Tenant.
Section 10.08. CONSEQUENTIAL DAMAGES. Notwithstanding anything to the
contrary contained in this Lease, nothing in this Lease shall impose any
obligations on Tenant or Landlord to be responsible or liable for, and each
hereby releases the other from all liability for, consequential damages other
than those consequential damages incurred by Landlord in connection with
holdover of the Property by Tenant after the expiration or earlier termination
of this Lease in accordance with, and subject to the provisions of Section 2.04
above.
Section 10.09. LANDLORD DEFAULT; LIMITED SELF-HELP RIGHT. Landlord shall
be deemed to be in default under this Lease, and a default of Landlord shall
have occurred if Landlord shall fail to perform any act or obligation required
of Landlord under this Lease, and should such failure continue for a period of
thirty (30) days following receipt by Landlord of written notice from Tenant of
the failure, requesting the performance of the act or obligation; provided,
however, that if Landlord cannot reasonably complete the cure or performance
within such 30-day period, then so long as Landlord commences such cure or
performance within thirty (30) days after receipt of such notice and thereafter
diligently pursues the same to completion, Landlord shall be deemed to have
timely cured such failure. In the event of any default of Landlord in accordance
with the foregoing, Tenant shall have available to it, and may pursue, any and
all rights and remedies available at law or in equity not expressly prohibited
in this Lease. Tenant shall have the right to make such temporary, emergency
repairs to the structural components of the Building, which are to be otherwise
made by Landlord under Section 6.03 above (but only to the extent as may be
reasonably necessary to prevent damage to the equipment, inventory or other
personal property of Tenant situated in the Building, or to prevent imminent
injury to persons). Tenant's limited self-help right described in the prior
sentence may only be exercised if Tenant has first provided Landlord with prior
notice reasonable under the circumstances stating that an emergency exists, the
nature of such emergency and the nature of the required repairs, and that Tenant
intends to immediately undertake the repair if Landlord does not do so within
twelve (12) hours following Landlord's receipt of such notice. The actual,
direct, and reasonable costs of Tenant's performance in lieu of Landlord's
performance shall be due and payable thirty (30) days after submission by Tenant
to Landlord of an invoice therefor (including the supporting documentation
described below), and if not timely paid, shall accrue Interest until paid.
Notwithstanding the foregoing, Tenant may not recover any costs that are
reimbursed to Tenant under any insurance policies carried by Tenant. In
addition, any requests for reimbursement made by Tenant shall be accompanied by
reasonable documentation showing the actual costs incurred by Tenant.
ARTICLE ELEVEN PROTECTION OF LENDERS
Section 11.01. SUBORDINATION. This Lease is subject and subordinate to all
present and future ground or underlying leases of the Project or Property, and
to the lien of any mortgages or trust deeds, now or hereafter in force against
the Project or Property, and to all renewals, extensions, modifications,
consolidations and replacements thereof, and to all advances made or hereafter
to be made upon the security of such mortgages or trust deeds, (i) unless the
holders of such mortgages or trust deeds, or the lessors under such ground lease
or underlying leases, require in writing that this Lease be superior thereto by
giving notice thereof to Tenant at least five (5) days before the election
becomes effective and (ii) so long as the holder of such mortgage or trust deed,
or the lessor under such ground lease or underlying lease agrees in writing, for
the benefit of Tenant, to accept this Lease and accept Tenant's occupancy as
provided in subsequent provisions of this Section 11.01. Tenant covenants and
agrees in the event any proceedings are brought for the foreclosure of any such
mortgage or trust deed, or if any ground or underlying lease is terminated, to
attorn to the purchaser upon any such foreclosure sale, or to the lessor of such
ground or underlying lease, as the case may be, if so requested to do so by such
purchaser or lessor, and to recognize such purchaser or lessor as the landlord
under this Lease, provided such lienholder or purchaser or ground lessor
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shall agree to accept this Lease and not disturb Tenant's occupancy, so long as
Tenant timely pays the rent and observes and performs all of the terms,
covenants and conditions of this Lease to be observed and performed by Tenant.
Landlord's interest herein may be assigned as security at any time to any
lienholder. Tenant shall, within fifteen (15) business days of request by
Landlord, execute such further instruments or assurances substantially in the
form attached hereto as Exhibit "B" or Exhibit "B-1" to evidence or confirm the
subordination or superiority of this Lease to any such mortgages, trust deeds,
ground leases or underlying leases, which shall expressly provide for the
non-disturbance of Tenant as provided in the foregoing provisions of this
Section 11.01, and if Tenant fails to do so timely, such failure shall
constitute a material default under this Lease, subject to the applicable notice
and cure provisions contained in this Lease. Tenant waives the provisions of any
current or future statute, rule or law which may give or purport to give Tenant
any right or election to terminate or otherwise adversely affect this Lease and
the obligations of Tenant hereunder in the event of any foreclosure proceeding
or sale. Notwithstanding anything to the contrary in this Section 11.01, the
subordination of the original Tenant's interest in this Lease to the lien of
Landlord's existing mortgage lender is conditioned on such lender's execution
and delivery to Tenant, for Tenant's execution, of the subordination
non-disturbance, and attornment agreement attached as Exhibit "B" to this Lease,
with such execution and delivery to Tenant being made no later than thirty (30)
days following full execution and delivery of this Lease by Landlord and Tenant.
In case of any future permanent (term) loan or refinancing of such future loan,
Landlord agrees to cause its then lender to execute and deliver to Tenant for
Tenant's execution, a subordination, non-disturbance and attornment agreement in
substantially the form of that attached as Exhibit "B-1" to this Lease.
Section 11.02. ESTOPPEL CERTIFICATES.
(a) Upon Landlord's written request, Tenant shall execute,
acknowledge and deliver to Landlord a written estoppel certificate substantially
in the form attached hereto as Exhibit "C" or such other commercially-reasonable
form as may be reasonably requested by Landlord's purchaser or encumbrance so
long as such certificate merely estops Tenant as a matter of legal defense and
does not create any right of action against Tenant and does not impose on Tenant
any affirmative obligation (such as providing additional notices of default) or
negative obligation (such as forbearing enforcement for additional cure
periods). Tenant shall deliver such certificate to Landlord within fifteen (15)
business days after Landlord's request. Landlord may give any such certificate
by Tenant to any prospective purchaser or encumbrancer of the Property. Such
purchaser or encumbrancer may rely conclusively upon such statement as true and
correct.
(b) If Tenant does not deliver such statement to Landlord within
such fifteen (15) business day period, Landlord, and any prospective purchaser
or encumbrancer, may conclusively presume and rely upon the following: (i) that
the terms and provisions of this Lease have not been changed except as set forth
in written amendments to this Lease attached thereto and reflecting the
signatures of both Landlord and Tenant; (ii) that this Lease has not been
canceled or terminated; (iii) that not more than one month's Base Rent or other
charges have been paid in advance; and (iv) that Landlord is not in default
under this Lease. In such event, Tenant shall be estopped from denying the truth
of the foregoing.
Section 11.03. TENANT'S FINANCIAL CONDITION. Within fifteen (15) business
days after written request from Landlord, Tenant shall deliver to Landlord such
financial statements, as Landlord reasonably requires, to verify the net worth
of Tenant or any Transferee or Permitted Purchaser (if such verification of net
worth is required under the terms of this Lease). Tenant represents and warrants
to Landlord that each such financial statement is a true and accurate statement
as of the date of such statement. All financial statements shall be confidential
and shall be used only for the purposes set forth in this Lease. Notwithstanding
any language in this Section 11.03, Tenant need not provide Landlord with copies
of Tenant's financial statements if they are public record or available to the
public through filings with any governmental authority.
ARTICLE TWELVE LEGAL COSTS
Section 12.01. LEGAL PROCEEDINGS. If any legal action for breach of or to
enforce the provisions of this Lease is commenced, the court in such action
shall award to the party in whose favor a judgment is entered, a reasonable sum
as attorneys' fees and costs. The losing party in such action shall pay such
attorneys' fees and costs. Tenant shall also indemnify Landlord against and hold
Landlord harmless from all costs, expenses, demands and liability Landlord may
incur if Landlord becomes or is made a party to any claim or action (a)
instituted by Tenant
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against any third party, or by any person holding any interest under or using
the Property by license of or agreement with Tenant; (b) for foreclosure of any
lien for labor or material furnished to or for Tenant or such other person; (c)
otherwise arising out of or resulting from any act or transaction of Tenant or
such other person; or (d) necessary to protect Landlord's interest under this
Lease in Tenant's bankruptcy case, or other proceeding under Title 11 of the
United States Code, as amended. Tenant shall defend Landlord against any such
claim or action at Tenant's expense with Tenant's counsel or other counsel
reasonably acceptable to Landlord. Notwithstanding the above, Tenant's indemnity
obligations as set forth above shall not include any claims based on Landlord's
actual or claimed acts or omissions.
ARTICLE THIRTEEN BROKERS
Landlord and Tenant hereby warrant to each other that they have had no
dealings with any real estate broker or agent in connection with the negotiation
of this Lease, and that they know of no other real estate broker or agent who is
entitled to a commission in connection with this Lease, excepting only the real
estate brokers or agents named in Section 1.09 above (the "Brokers"). Each party
agrees to indemnify and defend the other party against and hold the other party
harmless from any and all claims, demands, losses, liabilities, lawsuits,
judgments, and costs and expenses (including without limitation reasonable
attorneys' fees) with respect to any leasing commission or equivalent
compensation alleged to be owing on account of the indemnifying party's dealings
with any real estate broker or agent, other than the Brokers. Landlord's Broker
hereby discloses to Landlord and Tenant, and Landlord and Tenant hereby consent
to Landlord's Broker acting in this transaction as the agent of Landlord
exclusively. It is hereby acknowledged that Majestic Realty Co., identified in
Section 1.09 above as Landlord's Broker, and Rodman C. Martin, are acting as
both principal (that is, they have an interest in the Landlord entity) and
broker in this lease transaction. Landlord shall pay a commission to the Brokers
pursuant to the terms of a separate written agreement.
ARTICLE FOURTEEN BUILDING SHELL AND TENANT IMPROVEMENTS
Section 14.01. BUILDING SHELL IMPROVEMENTS. Subject to obtaining all
necessary governmental approvals (and subject to any changes mandated by the
applicable governmental authorities as a condition to obtaining such approvals),
Landlord shall use commercially reasonable efforts to construct the Building and
the surrounding and associated Common Areas, Common Area Improvements and other
improvements generally shown on the attached Exhibit "A" (using Landlord's
customary materials, methods, and means of construction, modified as required to
construct in conformance with the Building Shell Plans (as defined below) prior
to the Estimated Substantial Completion Date, or as soon thereafter as is
practicable (collectively, the "BUILDING SHELL IMPROVEMENTS"). The Building
Shell Improvements shall not include the Tenant Improvements (defined below) or
any improvements to the Additional Land. The Building Shell Improvements shall
be constructed according to those certain construction drawings identified on
the list attached as Exhibit "H" to this Lease (the "BASE BUILDING SHELL
PLANS"), as modified and supplemented by those construction drawings identified
on the list attached as Exhibit "I" to this Lease, plus all Change Orders (as
defined in Section 14.02(c)) for Building Shell Improvements approved by Tenant
(collectively, the "MODIFIED BUILDING SHELL PLANS"). If any of the construction
drawings listed on Exhibit "H" or Exhibit "I" are modified or supplemented, or
if additional construction drawings are hereafter prepared, Landlord shall
immediately provide copies of all such revisions and construction drawings to
Tenant. The Base Building Shell Plans, as modified by the Modified Building
Shell Plans are collectively referred to in this Lease as the "BUILDING SHELL
PLANS." The Building Shell Improvements, including Common Area Improvements, to
be constructed as reflected in the Base Building Shell Plans include the
following:
(a) UTILITY CONNECTION FEES. All connection fees, "hook-up" fees and
similar fees imposed by utility-providing entities or agencies relative to that
portion of the Building Shell Improvements identified in the Base Building Shell
Plans, including, but not limited to those imposed by the Las Vegas Valley Water
District and the Clark County Water Reclamation District.
(b) PERMIT FEES. All fees of any kind or nature required to be paid
for, or prior to, the issuance of any and all building permits and other permits
required for construction of that portion of the Building Shell Improvements
identified in the Base Building Shell Plans.
Landlord shall construct those portions of the Building Shell Improvements
described in the Base Building Shell Plans at no cost or expense to Tenant other
than the Rent payable under this Lease. The Building Shell
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Improvements described in the Base Building Shell Plans, including those Common
Area Improvements located on the Building Premises (other than the ESFR System),
are referred to herein as the "BASE BUILDING SHELL IMPROVEMENTS." Tenant shall
be solely responsible for the difference between (i) the total costs and
expenses of constructing the Building Shell Improvements and (ii) the total
costs and expenses that would have been incurred in constructing the Base
Building Shell Improvements reflected in the Base Building Shell Plans and all
Common Area Improvements included within the Base Building Shell Plans, which
difference in costs is referred to in this Lease as the "MODIFICATION COSTS."
The changes to the Base Building Shell Improvements resulting from the
modification and supplementation of the Base Building Shell Plans by the
Modified Building Shell Plans are herein referred to as the "BUILDING
MODIFICATIONS."
Section 14.02. TENANT IMPROVEMENTS AND SUBSTANTIAL COMPLETION.
(a) In addition to the Building Shell Improvements, and subject to
obtaining all necessary governmental approvals (and subject to any changes
mandated by the applicable governmental authorities as a condition to obtaining
such approvals), Landlord shall, at Tenant's sole cost and expense, construct
additional improvements (beyond the Building Shell Improvements) desired by
Tenant, including, without limitation, additional Building systems (including
HVAC) and office improvements for the Building and improvements for the
Additional Land, which may include buildings, structures, paving, lighting,
landscaping, screening, street improvements, and utilities (collectively, the
"TENANT IMPROVEMENTS") according to, and in conformance with the Final Plans as
defined below.
Landlord acknowledges having received Tenant's initial design development
drawings for the Tenant Improvements. Landlord acknowledges having received
additional construction drawings for building structures comprising Tenant
Improvements (the "CONSTRUCTION DRAWINGS"). Landlord and Tenant's Architect have
met and discussed the Construction Drawings. Tenant shall have final plans and
specifications prepared for the Tenant Improvements, taking into consideration
Landlord's comments. The final plans and specifications for Tenant Improvements
prepared pursuant to the foregoing, as revised, modified and supplemented from
time to time by Change Orders for the Tenant Improvements, are herein referred
to as the "FINAL PLANS."
On or before December 11, 2006, Landlord shall cause Landlord's Contractor
to provide Tenant with a written proposed guaranteed maximum price (the
"GUARANTEED MAXIMUM PRICE") for the Tenant Improvement Contract (as defined
below in this Section 14.02). The proposed Guaranteed Maximum Price may include
reasonable allowances (some of which may be provided by Tenant's Architect to
Landlord's Contractor in the absence of specifications or other detail not yet
available and not included in the Construction Drawings) for some of the work
("ALLOWANCE WORK") to take into account detail not included in the Construction
Drawings and anticipated differences between the Construction Drawings and the
Final Plans. The Guaranteed Maximum Price, once provided to Tenant, is to be
used by Tenant in determining whether to exercise the Termination Option
(defined in Article Twenty below). If Tenant does not timely exercise the
Termination Option, Landlord and Tenant acknowledge and agree that the
Guaranteed Maximum Price determined pursuant to this paragraph will also serve
as the Guaranteed Maximum Price to be subsequently identified in the Tenant
Improvement Contract (the "TIC GUARANTEED MAXIMUM PRICE"), provided that (a) the
scope of the work described in the Tenant Improvement Contract is materially the
same as the scope of the work described in the Construction Drawings, and (b)
the actual cost of the Allowance Work, as constructed in conformance with the
Final Plans and in the manner set forth in the Tenant Improvement Contract, does
not exceed the amount of such allowances. If, instead, the scope of the work is
materially different or the cost of the Allowance Work exceeds the allowances,
then in the case of either or both, the TIC Guaranteed Maximum Price may exceed
the Guaranteed Maximum Price by the sum total of (i) the increased cost
resulting from the differing scope of the work and (ii) the amount by which the
cost of the Allowance Work exceeds the allowances.
If, in the course of Landlord's seeking the necessary governmental
approvals of the Final Plans and obtaining the building permits required for
construction of the Tenant Improvements from the appropriate governmental
authorities such authorities impose any changes in the Final Plans as a
condition to obtaining such approvals and permits, Landlord shall provide
written notice to Tenant of any such impositions ("LANDLORD'S NOTICE"). Unless
Tenant, within ten (10) business days after receipt of Landlord's Notice,
objects in writing to the imposed changes in the Final Plans and specifically
describes the basis for such objection ("TENANT'S OBJECTION"), Tenant shall be
deemed to have waived any objection to the imposed changes and their effect on
the Property. If
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Tenant timely objects, then Landlord, with Tenant's cooperation, shall
thereafter attempt to resolve the matter to Tenant's reasonable satisfaction.
Landlord shall have the Tenant Improvements constructed by Landlord's
Contractor under and pursuant to a construction contract in the form attached as
Exhibit "K" hereto (the "TENANT IMPROVEMENT CONTRACT"). Landlord shall execute
the Tenant Improvement Contract and shall cause Landlord's Contractor to execute
the Tenant Improvement Contract upon written request from Tenant to Landlord
that Landlord initiate construction of the Tenant Improvements, which written
request shall also include Tenant's written acceptance of all of the final terms
of the Tenant Improvement Contract ("TENANT'S REQUEST AND ACCEPTANCE NOTICE").
Failure of Landlord to so execute or so cause Landlord's Contractor to execute
the Tenant Improvement Contract within ten (10) business days following
Landlord's receipt of Tenant's Request and Acceptance Notice shall constitute a
material default of Landlord hereunder, which, notwithstanding any other
provision of this Lease to the contrary, shall permit Tenant to thereafter
terminate this Lease by written notice to Landlord. Subject to the terms of
Article Twenty below, in the absence of Tenant's Request and Acceptance Notice,
Landlord shall have no obligation to construct the Tenant Improvements, but all
other rights and obligations of Landlord and Tenant under this Lease shall
remain unaffected.
Tenant shall be responsible for all costs of constructing the Tenant
Improvements ("TENANT'S COSTS"), which shall be paid by Tenant to Landlord as
follows: Tenant shall disburse to Landlord on a monthly basis the amount
sufficient for Landlord to pay Landlord's Contractor the monthly amount then
owing to Landlord's Contractor (based on applications for payment submitted to
Landlord by Landlord's Contractor under the Tenant Improvement Contract,
reflecting the portion of the work completed during the prior month as approved
in writing by Tenant's Architect. Such monthly payments shall be made by Tenant
to Landlord within twenty (20) days following Tenant's receipt of written
approval by Tenant's Architect of the application for payment submitted by
Landlord's Contractor to Landlord. If Tenant's payment of these sums is delayed
beyond such 20-day period, Landlord may direct Landlord's Contractor to suspend
the work, in which case Tenant shall be responsible for payment of reasonably
and actually incurred costs to which Landlord's Contractor may be entitled based
upon such suspension. All applications for payment submitted by Landlord's
Contractor shall be submitted with all such invoices and supporting
documentation as Tenant and Tenant's Architect may reasonably request. Tenant
shall provide in Tenant's contract with Tenant's Architect that the Architect
review applications for payment and communicate approval or disapproval thereof
(and the reasons for any disapproval) to Landlord and Tenant within ten (10)
days of receipt of the application for payment and all requested invoices and
supporting documents and all other documentation provided for in the Tenant
Improvement Contract.
(b) CONSTRUCTION RECORDS. The Building Shell Improvements and the
Tenant Improvements, to the extent designed by Landlord's design consultants and
constructed by Landlord's Contractor, shall be designed and constructed on an
"open book" basis with Tenant. Landlord shall keep, and shall cause Landlord's
Contractor and design consultants to keep, full and accurate accounts, records,
books, journals, ledgers, and data with respect to the direct expenses incurred
by Landlord's Contractor and design consultants in completing the Building Shell
Improvements and the Tenant Improvements pursuant to this Lease (the "RECORDS"),
which shall truthfully, accurately, and fully document the costs incurred in
connection with the construction of the Building Shell Improvements and the
Tenant Improvements. Tenant shall have the right, through its designated
representatives, during regular business hours, to inspect the Records as may be
reasonably necessary to verify performance by Landlord, Landlord's Contractor
and Landlord's design consultants of their respective obligations with regard to
construction of the Building Shell Improvements and the Tenant Improvements.
Landlord and Landlord's Contractor shall retain all Records for at least three
(3) years following the later of the date of Substantial Completion of the
Building Shell Improvements and the date of Substantial Completion of the Tenant
Improvements, and make the same available from time to time to Tenant and its
designated representatives during regular business hours at Landlord's offices
in Las Vegas, Nevada, within ten (10) days after receipt of a written request
for inspection from Tenant.
(c) CHANGES. Tenant may request a change to any part of the Building
Shell Improvements or the Tenant Improvements by providing written notice to
Landlord in which Tenant specifies with particularity the requested changes.
Within ten (10) business days of Landlord's receipt of Tenant's request for
changes ("CHANGES"), Landlord shall review the Changes requested and notify
Tenant in writing ("CHANGE ORDER") of any increase or decrease in the cost of
the Building Shell Improvements or the Tenant Improvements and the amount of any
delay that would result from the Change. Any delay that results from
Tenant-requested Changes to the Building
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Shell Improvements shall constitute a Tenant Delay if the critical path for
construction of the Building Shell Improvements is affected. Tenant shall
approve or disapprove the Change Order in writing before the expiration of ten
(10) business days following receipt of the Change Order. Any failure to approve
shall constitute a disapproval. Any and all costs, fees and expenses reasonably
incurred by Landlord relative to a Tenant-approved Change Order to (a) evaluate
a Tenant-requested Change, and (b) to change the Building Shell Improvements or,
the Tenant Improvements and to incorporate the Changes into the Building Shell
Improvements or, the Tenant Improvements contemplated under the Change Order
shall be expressly set forth in the Change Order and shall be paid by Tenant if
the Change Order is approved by Tenant. If such costs are incurred during the
course of Landlord's construction of the Tenant Improvements, such costs shall
be paid as provided above with respect to payment of Tenant's Costs. If such
costs are incurred by Landlord in connection with its construction of the
Building Shell Improvements, such costs shall be paid as provided in Section
14.02(e) below.
(d) SUBSTANTIAL COMPLETION. If the Building Shell Improvements are
not Substantially Completed by the Estimated Substantial Completion Date, then
the Lease Commencement Date shall be one hundred eighty (180) days following the
date the Building Shell Improvements would have been Substantially Completed but
for any Tenant Delay, subject to the provisions of Section 2.02 above. Tenant
agrees that any Tenant Delay shall be cumulative and shall not cause the Lease
Commencement Date to be extended beyond what it otherwise would have been in the
absence of any Tenant Delay. For purposes of this Lease, the Building Shell
Improvements shall be Substantially Completed when (a) all of such improvements
are completed, except for minor items of work (e.g., pick-up, "punch list" work,
etc.) that can be completed with only minor interference with construction and
installation of the Tenant Improvements, which shall be itemized on a punch list
and completed by Landlord within sixty (60) days following the date of
Substantial Completion of the Building Shell Improvements, (b) the Clark County
Building Department has conducted its final inspection of all Building Shell
Improvements, has provided its approval thereof, and has issued a Certificate of
Completion therefor, and (c) upon written notice from Landlord to Tenant of the
foregoing, accompanied by a copy of such Certificate of Completion and expressly
granting Tenant possession and occupancy of the Building Shell Improvements
("SUBSTANTIALLY COMPLETED" or "SUBSTANTIAL COMPLETION" of the Building Shell
Improvements, or similar phrase). For purposes of this Lease , the Tenant
Improvements shall be Substantially Completed when (a) all of such improvements
are completed, except for minor items of work (e.g., pick-up, "punchlist work,"
etc.) that can be completed with only minor interference with Tenant's conduct
of business at the Property, and (b) the issuance of a final unconditional
Certificate of Occupancy for the Property.
(e) TENANT'S SHARE OF BUILDING SHELL COSTS. During the course of
construction of the Building Shell Improvements, no more than monthly, Landlord
shall provide Tenant an itemized statement ("TENANT'S BUILDING SHELL COST
STATEMENT") setting forth the Modification Costs incurred during the prior month
for constructing Building Modifications, including any Changes related thereto
approved by Tenant, which are costs for which Tenant is responsible under this
Lease. Tenant's Building Shell Cost Statement (i) shall be accompanied by such
invoices and other documentation as Tenant may reasonably request, (ii) shall be
subject to written approval by Tenant's Architect or other contract
administration personnel and (ii) shall be subject to review and audit by Tenant
and its representatives, which may include an audit of the Records. Within
twenty (20) days following receipt of written approval by Tenant's Architect or
other contract administration personnel of Tenant's Building Shell Cost
Statement, Tenant shall pay the approved portion of the Modification Costs to
Landlord. If audit or review results in a determination of revised Modification
Costs for any monthly period, Landlord or Tenant shall pay to the other any
applicable overpayment or underpayment within thirty (30) days following such
determination. Tenant shall provide in Tenant's contract with Tenant's Architect
or other contract administration personnel that the Architect or other contract
administration personnel review Tenant's Building Shell Cost Statement and
communicate their approval or disapproval thereof (and the reasons for any
disapproval) to Landlord and Tenant within ten (10) days of receipt of Tenant's
Building Shell Cost Statement and all requested invoices and other
documentation. Tenant shall be entitled to reduction of, and credit against, the
first payments due under this Section 14.02(e) in the cumulative amount of all
advances and/or payments made by Tenant to Landlord for Modification Costs,
whether such advances or payments are so characterized, and whether such
advances or payments are made before or after execution of this Lease.
(f) TENANT DELAY. As used in this Lease, "Tenant Delay" shall mean,
in addition to the Tenant Delay specifically described above in this Article
Fourteen, any delay caused by (a) any Tenant-requested and approved Changes; (b)
any act or omission of Tenant or its employees, agents or contractors,
including, but not
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limited to, any interference with the construction of the Building Shell
Improvements; and (c) any unreasonable delays by Tenant in providing Landlord
with information requested by Landlord, or in providing consents or approvals
required to be given by Tenant.
During the Lease Term, the Base Building Shell Improvements shall be the
property of Landlord, the Building Modifications and the Tenant Improvements and
other Tenant's Alterations shall be the property of Tenant. The Building Shell
Improvements and the Tenant Improvements shall remain upon and be surrendered
with the Property upon the expiration or earlier termination of the Lease Term,
subject to the other provisions of this Lease.
Notwithstanding any language to the contrary in this Section 14.02,
neither Landlord nor Landlord's Contractor shall be responsible for tracking the
compliance with the requirements for obtaining LEED certification for the Tenant
Improvements. Any such work related to obtaining such certification shall be
performed by Tenant or Tenant's consultants at Tenant's sole cost and expense.
Section 14.03. NO OTHER IMPROVEMENTS. Except for the Building Shell
Improvements, the Tenant Improvements, and any unfinished "punch list" items,
Landlord shall have no liability or obligation for making any further
alterations or improvements of any kind in or about the Property.
Section 14.04. NO POSTED SECURITY REQUIREMENTS. Notwithstanding the
provisions of Section 6.05 above, Landlord acknowledges and agrees that Tenant
is not required to comply with the Posted Security Requirements with respect to
any work of improvement to be undertaken by Landlord in constructing the
Building Shell Improvements and/or the Tenant Improvements. Further, Landlord
shall obtain the express written waiver by Landlord's Contractor of any right to
stop work on either the Building Shell Improvements or the Tenant Improvements
pursuant to the provisions of the Posted Security Requirements.
ARTICLE FIFTEEN TELECOMMUNICATIONS SERVICES
Section 15.01. TENANT'S TELECOMMUNICATIONS EQUIPMENT. Subject to all
Applicable Laws, Tenant may, at Tenant's sole cost and expense, install antennae
and related facilities and other equipment for the provision of
telecommunications services (the "TELECOMMUNICATIONS EQUIPMENT") on the rooftop
or in other portions of the Building or elsewhere on the Property, but only if
such use is solely limited to Tenant's own use in the conduct of its business
("TENANT'S TELECOMMUNICATIONS EQUIPMENT"); provided, however, that co-location
of equipment supplied by third parties on Tenant's Telecommunications Equipment
shall be permitted without Landlord's prior written approval. Tenant shall be
solely responsible for all costs and expenses related to the use and maintenance
of Tenant's Telecommunications Equipment, the removal of which upon the
expiration or earlier termination of this Lease shall be governed by Section
6.06 of this Lease. All operations by Tenant pursuant to this Article shall be
lawful and in compliance with all rules and regulations of the Federal
Communications Commission, Federal Aviation Administration, and Clark County
Department of Aviation. Consistent with the terms of Section 6.05 above,
Landlord shall have the right, in its reasonably exercised discretion, to
determine the location of any visible Tenant's Telecommunications Equipment on
the Building; provided, however, that Landlord shall not require any location
that precludes or interferes with the intended operation of Tenant's
Telecommunications Equipment. Regardless of any roof warranty or any repair
obligations of Landlord in this Lease, Tenant shall be solely responsible for
the repair of any leaks or other damage to the roof membrane resulting from the
installation of any Tenant's Telecommunications Equipment. Landlord shall
include language in all other leases for space in the Project requiring the
tenants under such leases to operate any of their Telecommunications Equipment
in compliance with all rules and regulations of the Federal Communications
Commission, Federal Aviation Administration, and Clark County Department of
Aviation.
ARTICLE SIXTEEN MISCELLANEOUS PROVISIONS
Section 16.01. NON-DISCRIMINATION. Tenant promises, and it is a condition
to the continuance of this Lease, that there will be no discrimination against,
or segregation of, any person or group of persons on the basis of race, color,
sex, creed, national origin or ancestry in the leasing, subleasing,
transferring, occupancy, tenure or use of the Property or any portion thereof.
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Section 16.02. LANDLORD'S LIABILITY; CERTAIN DUTIES.
(a) As used in this Lease, the term "LANDLORD" means only the
current owner of the leasehold estate under a ground lease of the Property at
the time in question. Each Landlord is obligated to perform the obligations of
Landlord under this Lease only during the time such Landlord owns such interest
or title. Any Landlord who transfers its title or interest is relieved of all
liability with respect to the obligations of Landlord under this Lease to be
performed on or after the date of transfer. However, each Landlord shall deliver
to its transferee all funds that Tenant previously paid if such funds have not
yet been applied under the terms of this Lease.
(b) Tenant shall give written notice of any failure by Landlord to
perform any of its obligations under this Lease to Landlord and, if Landlord
expressly so requests in written notice thereof to Tenant, to any ground lessor,
mortgagee or beneficiary under any deed of trust encumbering the Property whose
name and address have been furnished to Tenant in writing in that notice.
Landlord shall not be in default under this Lease unless Landlord (or such
ground lessor, mortgagee or beneficiary) fails to cure or commence to cure such
non-performance within the period(s) specified in Section 10.09 above.
(c) Notwithstanding any term or provision herein to the contrary,
the liability of Landlord for the performance of its duties and obligations
under this Lease is limited to Landlord, and neither Landlord nor Landlord's
partners, members, managers, shareholders, officers or other principals shall
have any personal liability under this Lease.
(d) Except as otherwise expressly provided in this Lease, Tenant
shall have no right to terminate this Lease based on an uncured default by
Landlord in the performance of Landlord's obligations under this Lease;
provided, however, that in addition to all other rights and remedies not
expressly prohibited in this Lease, Tenant may seek to recover from Landlord an
amount representing appropriate actual, compensatory damages for breach of
contract based on any such uncured default of Landlord. Consistent with Section
10.08 above, in no event shall Tenant be permitted to recover consequential,
punitive, or exemplary damages from Landlord based on any such uncured default
of Landlord, or otherwise.
Section 16.03. SEVERABILITY. A determination by a court of competent
jurisdiction that any provision of this Lease or any part thereof is illegal or
unenforceable shall not cancel or invalidate the remainder of such provision or
this Lease, which shall remain in full force and effect, and it is the intention
of the parties that there shall be substituted for such provision as is illegal
or unenforceable a provision as similar to such provision as may be possible and
yet be legal and enforceable.
Section 16.04. INTERPRETATION. The captions of the Articles or Sections of
this Lease are to assist the parties in reading this Lease and are not a part of
the terms or provisions of this Lease. Whenever required by the context of this
Lease, the singular shall include the plural and the plural shall include the
singular. The masculine, feminine and neuter genders shall each include the
other. In any provision relating to the conduct, acts or omissions of Tenant,
the term "Tenant" shall include Tenant's agents, employees, contractors,
invitees, successors or others using the Property with Tenant's express or
implied permission. Any reference in this Lease to a "business day" refers to a
date that is not a Saturday, Sunday or legal holiday (or observed as a legal
holiday) for Nevada state government offices pursuant to NRS. If any deadline
specified in this Lease falls on a day that is not a business day, the deadline
shall be extended to the next business day.
Section 16.05. INCORPORATION OF PRIOR AGREEMENTS; MODIFICATIONS. This
Lease is the only agreement between the parties pertaining to the lease of the
Property and no other agreements are effective. All amendments to this Lease
shall be in writing and signed by all parties. Any other attempted amendment
shall be void.
Section 16.06. NOTICES. All notices, demands, statements or communications
(collectively, "NOTICES") given or required to be given by either party to the
other hereunder shall be in writing, shall be sent by United States certified or
registered mail, postage prepaid, return receipt requested,
nationally-recognized commercial overnight courier, or delivered personally (i)
to Tenant at the addresses set forth in Section 1.03 above, or (ii) to Landlord
at the addresses set forth in Section 1.02 above. Landlord or Tenant shall have
the right to change its respective Notice address upon giving Notice to the
other party. Any Notice will be deemed given three (3) business days after the
date it is mailed as provided in this Section 16.06, or upon the date delivery
is made, if delivered by an approved
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courier (as provided above) or personally delivered. Consistent with the
provisions of Section 16.02(b) above, if Tenant is notified as provided in this
Section 16.06 of the identity and address of Landlord's secured lender or ground
or underlying lessor, Tenant shall give to such lender or ground or underlying
lessor written notice of any default by Landlord under the terms of this Lease
by registered or certified mail or nationally-recognized commercial overnight
courier, and such lender or ground or underlying lessor shall be given the same
opportunity to cure such default as is provided Landlord under this Lease
(unless such cure period is extended pursuant to the terms of any agreement to
which Tenant is a party or to which Tenant consents) prior to Tenant's
exercising any remedy available to Tenant. Notices required hereunder may be
given by either an agent or attorney acting on behalf of Landlord or Tenant.
Section 16.07. WAIVERS. The failure of either party to insist upon the
strict performance, in any of one or more instances, of any term, covenant or
condition of this Lease shall not be deemed to be a waiver by that party of such
term, covenant or condition. No waiver of any breach of any term, provision and
covenant contained herein shall be deemed or construed to constitute a waiver of
any other or subsequent breach of any term, provision or covenant contained
herein. Landlord's acceptance of the payment of rent (or portions thereof) or
any other payments hereunder after the occurrence of and during the continuance
of a default unrelated to the payment of that rent (or with knowledge of a
breach of any term or provision of this Lease which with the giving of notice
and the passage of time, or both, would constitute such a default) shall not be
construed as a waiver of such default or any other rights or remedies of
Landlord, including any right of Landlord to recover the Property. Moreover,
Tenant acknowledges and agrees that Landlord's acceptance of a partial rent
payment shall not, under any circumstances (whether or not such partial payment
is accompanied by a special endorsement or other statement), constitute an
accord and satisfaction with regard to the unpaid balance of the rent. Landlord
will accept the check (or other payment means) for payment without prejudice to
Landlord's right to recover the balance of such rent or to pursue any other
remedy available to Landlord. Forbearance by Landlord to enforce one or more of
the remedies herein provided upon the occurrence of a default shall not be
deemed or construed to constitute a waiver of such default.
Section 16.08. NO RECORDATION. Tenant shall not record this Lease.
Concurrently with their execution of this Lease, Landlord and Tenant shall
execute a memorandum of this Lease in the form of that attached as Exhibit "F"
to this Lease (the "LEASE MEMORANDUM"), which shall be recorded at Landlord's
sole cost and expense.
Section 16.09. BINDING EFFECT; CHOICE OF LAW. This Lease binds any party
who legally acquires any rights or interest in this Lease from Landlord or
Tenant. However, Landlord shall have no obligation to Tenant's successor unless
the rights or interests of Tenant's successor are acquired in accordance with
the terms of this Lease. The laws of the state in which the Property is located
shall govern this Lease, without regard to such state's conflicts of law
principles. Landlord and Tenant agree that any action or claim brought to
enforce or interpret the provisions of this Lease, or otherwise arising out of
or related to this Lease or to Tenant's use and occupancy of the Property,
regardless of the theory of relief or recovery and regardless of whether third
parties are involved in the action, may only be brought in the State and County
where the Property is located, unless otherwise agreed in writing by the other
party prior to the commencement of any such action.
IN THE INTEREST OF OBTAINING A SPEEDIER AND LESS COSTLY ADJUDICATION OF
ANY DISPUTE, LANDLORD AND TENANT HEREBY KNOWINGLY, INTENTIONALLY, AND
IRREVOCABLY WAIVE THE RIGHT TO TRIAL BY JURY IN ANY LEGAL ACTION, PROCEEDING,
CLAIM, OR COUNTERCLAIM BROUGHT BY EITHER OF THEM AGAINST THE OTHER ON ALL
MATTERS ARISING OUT OF OR RELATED TO THIS LEASE OR THE USE AND OCCUPANCY OF THE
PROPERTY.
Section 16.10. INTENTIONALLY OMITTED.
Section 16.11. INTENTIONALLY OMITTED.
Section 16.12. FORCE MAJEURE. A "FORCE MAJEURE" event shall occur if
Landlord or Tenant cannot perform any of its obligations due to events beyond
such applicable party's control, except with respect to the obligations imposed
with regard to Base Rent, Additional Rent and other charges to be paid by Tenant
pursuant to this Lease, the time provided for performing such obligations shall
be extended by a period of time ("FORCE MAJEURE DELAY") equal to the duration of
such events. Events beyond Landlord's or Tenant's control include, but are not
limited to, acts of God, war, civil commotion, terrorist acts, labor disputes,
strikes, fire, flood or other casualty, shortages of labor or material,
government regulation or restriction, waiting periods atypical in Clark
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County, Nevada for obtaining governmental permits or approvals, or weather
conditions. No express reference in this Lease to a Force Majeure event shall
create any inference that the terms of this Section 16.12 do not apply with
equal force in the absence of such an express reference.
Section 16.13. COUNTERPARTS. This Lease may be executed in counterparts
and, when all counterpart documents are executed, the counterparts shall
constitute a single binding instrument.
Section 16.14. SURVIVAL. All representations and warranties of Landlord
and Tenant shall survive the termination of this Lease.
Section 16.15. RELATIONSHIP OF PARTIES. Nothing contained in this Lease
shall be deemed or construed by the parties hereto or by any third party to
create the relationship of principal and agent, partnership, joint venturer or
any association between Landlord and Tenant, it being expressly understood and
agreed that neither the method of computation of Rent nor any act of the parties
hereto shall be deemed to create any relationship between Landlord and Tenant
other than the relationship of landlord and tenant.
Section 16.16. NO WARRANTY. In executing and delivering this Lease, Tenant
has not relied on any representation, including, but not limited to, any
representation whatsoever as to the amount of any item comprising Additional
Rent or the amount of the Additional Rent in the aggregate or that Landlord is
furnishing the same services to other tenants, at all, on the same level or on
the same basis, or any warranty or any statement of Landlord which is not set
forth herein or in one or more of the exhibits attached hereto.
Section 16.17. INTENTIONALLY OMITTED.
Section 16.18. INDEPENDENT COVENANTS. This Lease shall be construed as
though the covenants herein between Landlord and Tenant are independent and not
dependent and Tenant hereby expressly waives the benefit of any statute or other
law to the contrary and agrees that if Landlord fails to perform its obligations
set forth herein, Tenant shall not be entitled to make any repairs or perform
any acts hereunder at Landlord's expense or to any setoff of the Rent or other
amounts owing hereunder against Landlord, except as otherwise expressly provided
in this Lease.
Section 16.19. CONFIDENTIALITY. Each party acknowledges that the content
of this Lease and any related documents are confidential information. Except
with respect to any disclosure required by law, each party shall keep such
confidential information strictly confidential and shall not disclose such
confidential information to any person or entity other than its financial,
legal, and design consultants, provided that such recipients agree to maintain
the confidentiality of the information.
Section 16.20. REVENUE AND EXPENSE ACCOUNTING. Landlord and Tenant agree
that, for all purposes (including any determination under Section 467 of the
Internal Revenue Code), rental income will accrue to the Landlord and rental
expenses will accrue to the Tenant in the amounts and as of the dates rent is
payable under this Lease.
Section 16.21. TENANT'S REPRESENTATIONS AND WARRANTIES. Tenant warrants
and represents to Landlord as follows, each of which is material and being
relied upon by Landlord:
(a) Tenant (i) is not, and shall not become, a person or entity with
whom Landlord is restricted from doing business under regulations of the Office
of Foreign Asset Control ("OFAC") of the Department of the Treasury (including,
but not limited to, those named on OFAC's Specially Designated and Blocked
Persons list), or under any statute, executive order (including, but not limited
to, the September 24, 2001 Executive Order Blocking Property and Prohibiting
Transactions with Persons who Commit, Threaten to Commit, or Support Terrorism),
or other governmental action, (ii) is not knowingly engaged and shall not
knowingly engage in any dealings or transactions with or otherwise be associated
with such persons or entities, and (iii) is not and shall not become, a person
or entity whose activities are regulated by the International Money Laundering
Abatement and Financial Anti-Terrorism Act of 2001, or the regulations or orders
thereunder.
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
43
(b) Tenant is duly organized, validly existing and in good standing
under the laws of the state of its organization, and is qualified to do business
in the state in which the Property is located, and the persons executing this
Lease on behalf of Tenant have the full right and authority to bind Tenant
without the consent or approval of any other person or entity. Tenant has full
power, capacity, authority and legal right to execute and deliver this Lease and
to perform all of its obligations hereunder. This Lease is a legal, valid and
binding obligation of Tenant, enforceable in accordance with its terms.
(c) Tenant has not (1) made a general assignment for the benefit of
creditors, (2) filed any voluntary petition in bankruptcy or suffered the filing
of an involuntary petition by any creditors, (3) suffered the appointment of a
receiver to take possession of all or substantially all of its assets, (4)
suffered the attachment or other judicial seizure of all or substantially all of
its assets, (5) admitted in writing its inability to pay its debts as they come
due, or (6) made an offer of settlement, extension or composition to its
creditors generally.
Tenant confirms that all of the above representations and warranties are true as
of the date of this Lease, and acknowledges and agrees that they shall survive
the expiration or earlier termination of this Lease.
Section 16.22. LANDLORD'S REPRESENTATIONS AND WARRANTIES. Landlord
warrants and represents to Tenant as follows, each of which is material and
being relied upon by Tenant:
Landlord (i) is not, and shall not become, a person or entity with whom Tenant
is restricted from doing business under regulations of the Office of Foreign
Asset Control ("OFAC") of the Department of the Treasury (including, but not
limited to, those named on OFAC's Specially Designated and Blocked Persons
list), or under any statute, executive order (including, but not limited to, the
September 24, 2001 Executive Order Blocking Property and Prohibiting
Transactions with Persons who Commit, Threaten to Commit, or Support Terrorism),
or other governmental action, (ii) is not knowingly engaged and shall not
knowingly engage in any dealings or transactions with or otherwise be associated
with such persons or entities, and (iii) is not and shall not become, a person
or entity whose activities are regulated by the International Money Laundering
Abatement and Financial Anti-Terrorism Act of 2001, or the regulations or orders
thereunder.
(a) Landlord is duly organized, validly existing and in good
standing under the laws of the state of its organization, and is qualified to do
business in the state in which the Property is located, and the persons
executing this Lease on behalf of Landlord have the full right and authority to
bind Landlord without the consent or approval of any other person or entity.
Landlord has full power, capacity, authority and legal right to execute and
deliver this Lease and to perform all of its obligations hereunder. This Lease
is a legal, valid and binding obligation of Landlord, enforceable in accordance
with its terms.
(b) Landlord has not (1) made a general assignment for the benefit
of creditors, (2) filed any voluntary petition in bankruptcy or suffered the
filing of an involuntary petition by any creditors, (3) suffered the appointment
of a receiver to take possession of all or substantially all of its assets, (4)
suffered the attachment or other judicial seizure of all or substantially all of
its assets, (5) admitted in writing its inability to pay its debts as they come
due, or (6) made an offer of settlement, extension or composition to its
creditors generally.
Landlord confirms that all of the above representations and warranties are true
as of the date of this Lease, and acknowledges and agrees that they shall
survive the expiration or earlier termination of this Lease.
Section 16.23. APPROVALS AND CONSENTS. Any approvals, consents,
authorizations or similar discretionary acceptances, endorsements and
ratifications required or provided for in this Lease shall not be unreasonably
withheld, conditioned or delayed, except in any case in which the action to be
taken is expressly described in this Lease as being within the "sole discretion"
of a party.
ARTICLE SEVENTEEN MASTER LEASE
(a) This Lease is subject and subordinate to that certain Lease
Agreement, dated November 15, 2005, as amended by that certain First Amendment
to Lease Agreement, dated June 20, 2006 (collectively, the "MASTER LEASE"), by
and between Landlord, as tenant, and County of Clark, a political subdivision of
the State of
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
44
Nevada ("COUNTY"), as landlord (the "MASTER LANDLORD"), and to any renewal,
amendment or modification thereof, and to any mortgage or other encumbrance to
which the Master Lease is subject or subordinate, and to all renewals,
modifications, consolidations, replacements and extensions thereof. A copy of
the Master Lease is attached as Exhibit "G" to this Lease. Except as
specifically modified in this Lease, during the Lease Term Tenant shall be bound
by and shall observe all of the terms and conditions to be observed by Landlord
under the Master Lease as fully and to the same extent and effect as though
Tenant were the lessee thereunder in the place and stead of Landlord. Any event
resulting in termination of the Master Lease by its terms or otherwise shall
also automatically result in termination of this Lease, except as otherwise
provided or contemplated in Section 2.3 (Attornment) of the Master Lease.
(b) Without limiting the generality of (a) above, Tenant expressly
agrees to comply with and be bound by any and all covenants, conditions and
restrictions or rules, regulations or standards of operation or conduct
contemplated under the terms of the non-discrimination provisions of Article III
of the Master Lease, which are hereby incorporated into this Lease by this
reference.
(c) Without limiting the generality of (a) above, Tenant
acknowledges and agrees that Landlord's covenant of quiet possession or
enjoyment (Section 5.08 of this Lease) is expressly subject to the Master
Landlord's rights under the Master Lease, including but not limited to the right
to recover the Property (Section 2.21 of the Master Lease), the right to improve
or expand McCarran International Airport (Section 3.10 of the Master Lease), and
the right to enter and inspect the Property (Section 2.7 of the Master Lease).
(d) Without limiting the generality of (a) above, Tenant
acknowledges and agrees that this Lease is subject to the attornment provisions
of Section 2.3 of the Master Lease. Pursuant to the provisions of such section
of the Master Lease, Section 11.01 of this Lease is supplemented by adding the
following thereto:
If by reason of a default on the part of Landlord as tenant in the
performance of the terms of the provisions of the Master Lease, the
Master Lease and the leasehold estate of Landlord as ground lessee
thereunder are terminated by summary proceedings or otherwise in
accordance with the terms of the Master Lease, Tenant will attorn to
Master Landlord and recognize Master Landlord as lessor; provided,
however, Master Landlord agrees that so long as Tenant is not in
default, Master Landlord agrees to provide quiet enjoyment to Tenant
and to be bound by all the terms and conditions of this Lease.
(e) Without limiting the generality of (a) above, Tenant further
acknowledges and agrees that (i) all Tenant signs must have the prior written
approval of the designated representative of Master Landlord (pursuant to
Section 2.6.2 of the Master Lease), and (ii) Master Landlord must be named as an
additional insured on all liability insurance policies maintained by Tenant
under the terms of this Lease (pursuant to Section 2.12.2.7.4 of the Master
Lease).
(f) As required by the terms of Section 2.9 of the Master Lease,
should Tenant cause any improvements to be made to the Property, Tenant shall
cause any contract with any contractor, designer, or other person providing
work, labor, or materials to the Property to include the following clause:
Contractor agrees on behalf of itself, its subcontractors, suppliers
and consultants and their employees that there is no legal right to
file a lien upon County-owned property and will not file a
mechanic's lien or otherwise assert any claim against County's real
estate or any County's leasehold interest on account of any work
done, labor performed or materials furnished under this contract.
Contractor agrees to indemnify, defend and hold the County and
Landlord harmless from any liens filed upon the County's property
and County's leasehold interest and shall promptly take all
necessary legal action to ensure the removal of any such lien at
Contractor's sole cost.
(g) Within twenty (20) days following full execution of this Lease
and the recordation of the Lease Memorandum, Landlord shall cause Nevada Title
Company to issue in favor of Tenant, as insured, a policy of
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
45
leasehold title insurance for Tenant's leasehold interest under this Lease, in
the form of the Pro-Forma Policy (2nd Amendment) prepared by Nevada Title
Company (Order No. 06-04-0139-JJA) (the "LEASEHOLD TITLE POLICY"). The Leasehold
Title Policy shall reflect the recording of (i) the executed Recognition
Nondisturbance and Attornment Agreement in the form of Exhibit "L" (in Schedule
A, item 2 of the Leasehold Title Policy) and (ii) the executed Subordination
Non-Disturbance and Attornment Agreement in the form of Exhibit B (in Schedule
B, Part 1, item 13 of the Leasehold Title Policy). The face amount of the
Leasehold Title Policy shall be Thirty Million Dollars ($30,000,000.00). The
Leasehold Title Policy shall be provided to Tenant by Landlord at no additional
cost or expense to Tenant, provided that if Tenant desires "extended coverage"
or any endorsements, Tenant shall be solely responsible for all costs associated
with obtaining the same, including the cost of any survey or other requirements
for such coverage and endorsements. Within thirty (30) days of written request
from Tenant, Landlord, at Landlord's cost shall undertake all commercially
reasonable actions to commence and diligently pursue to completion (including
all commercially reasonable efforts to have Master Landlord cooperate in such
efforts) the vacation, release and relinquishment of record of (i) all
right-of-way reservations and easements for roadway and public utilities
purposes and (ii) the rights and interests of any public utility-providing
agencies with respect thereto, as reserved and granted within the boundaries of
the Property in patents from the United States of America. Landlord shall
diligently pursue such efforts, but its failure to obtain a release of all such
matters of record despite and after expending all commercially reasonable
efforts shall not constitute a default under this Lease. If Landlord fails to
timely deliver the Leasehold Title Policy, and should such failure continue for
a period of thirty (30) days, following Tenant's written request to deliver the
Leasehold Title Policy, Landlord shall be in material default of this Lease.
Consistent with Section 16.02(d) above, Tenant may thereafter seek to recover
from Landlord an amount representing appropriate actual compensatory damages for
such default.
(h) Upon the full execution of this Lease, Landlord shall execute
and deliver to Master Landlord for execution and delivery to Tenant the
Recognition, Non-Disturbance and Attornment Agreement in the form of Exhibit "L"
attached hereto. Landlord shall diligently pursue the execution of that
Recognition, Non-Disturbance and Attornment Agreement by Master Landlord and the
delivery thereof to Tenant following such execution.
ARTICLE EIGHTEEN DECLARATION OF COVENANTS, CONDITIONS, RESTRICTIONS AND
RECIPROCAL EASEMENTS
Landlord may prepare for eventual recordation against the Property and
other adjacent land a Declaration of Covenants, Conditions, Restrictions and
Reciprocal Easements (the "DECLARATION"). So long as the provisions of the
Declaration do not affect Tenant's obligations in any material way (the
performance of ministerial acts shall not be deemed material) and do not affect
Tenant's use or conduct of business from the Property, Tenant will not
unreasonably withhold consent to a subordination of this Lease to the
Declaration, and further agrees to execute a recordable instrument (prepared by
Landlord at its sole cost and expense) in order to evidence any such
subordination.
ARTICLE NINETEEN NO OPTION OR OFFER
THE SUBMISSION OF THIS LEASE BY LANDLORD, ITS AGENT OR REPRESENTATIVE FOR
EXAMINATION OR EXECUTION BY TENANT DOES NOT CONSTITUTE AN OPTION OR OFFER TO
LEASE THE PROPERTY UPON THE TERMS AND CONDITIONS CONTAINED HEREIN OR A
RESERVATION OF THE PROPERTY IN FAVOR OF TENANT, IT BEING INTENDED HEREBY THAT
THIS LEASE SHALL ONLY BECOME EFFECTIVE UPON THE EXECUTION HEREOF BY LANDLORD AND
DELIVERY OF A FULLY EXECUTED LEASE TO TENANT. NEITHER PARTY SHALL HAVE ANY
OBLIGATION TO CONTINUE DISCUSSIONS OR NEGOTIATIONS OF THIS LEASE.
ARTICLE TWENTY CONDITION SUBSEQUENT
At any time prior to the earlier of (i) Landlord's receipt of Tenant's
Request and Acceptance Notice (defined in Section 14.02 above), (ii) the
expiration of five (5)
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
46
business days following Tenant's receipt from Landlord's Contractor of written
notice of the proposed Guaranteed Maximum Price pursuant to Section 14.02 above,
or (iii) December 14, 2006, Tenant shall have the option and right to terminate
this Lease (the "TERMINATION OPTION"), by providing written notice to Landlord
of the same, subject to Landlord's receipt, within five (5) business days
following its receipt of Tenant's termination notice, in immediately available
funds, of the sum of Five Million Dollars ($5,000,000.00) (the "TERMINATION
FEE") in consideration for the exercise by Tenant of the Termination Option. If
the above terms of the Termination Option are not strictly complied with
(including Landlord's timely receipt of the Termination Fee), then the
Termination Option shall be rendered null and void and any purported exercise
shall be ineffective. Assuming the Termination Option is timely and validly
exercised and the Lease is terminated, then following such termination neither
Landlord nor Tenant shall have any further obligations to the other under this
Lease, excepting those obligations which have accrued prior to or which
expressly survive such termination. Time is of the essence with respect to
Tenant's rights under this Article Twenty. Tenant shall be entitled to reduction
of, and credit against, the Termination Fee due under this Article Twenty in the
cumulative amount of all advances and /or payments made by Tenant to Landlord
for Modification Costs, whether such advances or payments are so characterized,
and whether such advances or payments are made before or after execution of this
Lease.
(Left intentionally blank - signature page to follow)
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
47
Landlord and Tenant have signed this Lease at the place and on the dates
specified adjacent to their signatures below.
LANDLORD:
Signed on_____________, 2006 BELTWAY BUSINESS PARK WAREHOUSE NO. 2, LLC,
at__________________________ a Nevada limited liability company
By: MAJESTIC BELTWAY WAREHOUSE
BUILDINGS, LLC, a Delaware
limited liability company, its Manager
By: MAJESTIC REALTY CO.,
a California corporation,
Manager's Agent
By:/s/ Edward P. Roski, Jr.
Name:Edward P. Roski, Jr.
Its:Chairman and Chief Executive Officer
By: THOMAS & MACK BELTWAY, L.L.C.,
a Nevada limited liability company,
its Manager
By:.s. Thomas A. Thomas
|
Name: Thomas A. Thomas
Its: Manager
TENANT:
Signed on December 11, 2006 NEVADA POWER COMPANY,
at_________________________ a Nevada corporation
By:/s/ Walter M. Higgins
Printed Name: Walter M. Higgins
Its: Chief Executive Officer
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
|
48
EXHIBIT A
DEPICTION OR DESCRIPTION OF THE PROPERTY
(Attached)
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
A-1
[DIAGRAMS OF LEASED PROPERTY]
THENCE SOUTH 00(degree)54'27" WEST, 40.08 FEET TO A POINT ON THE NORTH LINE OF
THE SOUTH HALF (S 1/2) OF THE SOUTHEAST QUARTER (SE 1/4) OF THE SOUTHWEST
QUARTER (SW 1/4) OF SAID SECTION 01;
THENCE ALONG SAID LINE, SOUTH 87(degree)14'47" WEST, 630.64 FEET TO THE
NORTHWEST CORNER OF SAID SOUTH HALF (S 1/2);
THENCE ALONG THE WEST LINE OF THE NORTH HALF (N 1/2) OF THE SOUTHEAST QUARTER
(SE 1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF SAID SECTION 01, NORTH
01(degree)05'30" EAST, 652.21 FEET;
THENCE DEPARTING SAID WESTERLY LINE AND ALONG A LINE 16.50 FEET SOUTH OF AND
PARALLEL TO THE NORTHERLY LINE OF THE SOUTHEAST QUARTER (SE 1/4) OF SAID
SOUTHWEST QUARTER (SW 1/4) NORTH 87(degree)13'43" EAST, 1083.01 FEET TO THE
POINT OF BEGINNING.
CONTAINING: 16.00 ACRES OF LAND.
BASIS OF BEARINGS
THE EAST LINE OF THE NORTHEAST QUARTER (NE 1/4) OF THE NORTHEAST QUARTER (NE
1/4) OF SECTION 1, TOWNSHIP 22 SOUTH, RANGE 60 EAST, M.D.M., CLARK COUNTY,
NEVADA, AS SHOWN ON THAT MAP ON FILE IN FILE 66 OF SURVEYS AT PAGE 02 OF
OFFICIAL RECORDS, CLARK COUNTY, NEVADA, SAID LINE BEARS NORTH 00(degree)42'44"
WEST.
GLEN J. DAVIS
PROFESSIONAL LAND SURVEYOR
NEVADA CERTIFICATE NO 11825
EXPIRES 12/31/06
LOCHSA SURVEYING
(702) 365-9312 / FAX (702) 320-1769
[DIAGRAMS OF LEASED PROPERTY]
LEGAL DESCRIPTION
BBP WAREHOUSE II
PORTION OF A.P.N.: 176-01-301-032
BEING A PORTION OF THE SOUTHWEST QUARTER (SW 1/4) OF SECTION 1, TOWNSHIP 22
SOUTH, RANGE 60 EAST, M.D.M., CLARK COUNTY, NEVADA, MORE PARTICULARLY DESCRIBED
AS FOLLOWS:
M.D.M., CLARK COUNTY, NEVADA, MORE PARTICULARLY DESCRIBED AS FOLLOWS:
BEGINNING AT THE NORTHWEST CORNER OF THE SOUTHEAST QUARTER (SE 1/4) OF THE
NORTHEAST QUARTER (NE 1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF THE SOUTHWEST
QUARTER (SW 1/4) OF SAID SECTION 01;
THENCE ALONG THE NORTH LINE THEREOF, NORTH 87(degree)13'39" EAST, 314.79 FEET TO
THE NORTHEAST CORNER OF SAID SOUTHEAST QUARTER (SE 1/4);
THENCE ALONG THE EAST LINE THEREOF, SOUTH 01(degree)05'30" WEST, 334.37 FEET TO
THE NORTH LINE OF THE SOUTH HALF (S 1/2) OF THE SOUTHEAST QUARTER (SE 1/4) OF
THE SOUTHWEST QUARTER (SW 1/4) OF SAID SECTION 01;
THENCE ALONG SAID NORTH LINE, NORTH 87(degree)14'47" EAST, 630.64 FEET TO A
POINT HEREINAFTER KNOWN AS "POINT A";
THENCE DEPARTING SAID NORTH LINE AND ALONG THE EAST LINE OF THE SOUTHWEST
QUARTER (SW 1/4) OF THE SOUTHEAST QUARTER (SE 1/4) OF THE SOUTHWEST QUARTER (SW
1/4) OF SAID SECTION 01, SOUTH 00(degree)54'27" WEST, 161.72 FEET TO A
NON-TANGENT 56.00 FEET RADIUS CURVE, A RADIAL LINE TO SAID POINT BEARS SOUTH
16(degree)58'33" WEST;
THENCE ALONG SAID CURVE CONCAVE SOUTHEASTERLY THROUGH A CENTRAL ANGLE OF
171(degree)46'44", AN ARC LENGTH OF 167.89 FEET TO A REVERSE 14.50 FEET RADIUS
CURVE, A RADIAL LINE TO SAID POINT BEARS SOUTH 25(degree) 11'49" WEST;
THENCE ALONG SAID CURVE CONCAVE SOUTHWESTERLY THROUGH A CENTRAL ANGLE OF
65(degree)42'38", AN ARC LENGTH OF 16.63 FEET;
THENCE SOUGH 00(degree)54'27" WEST, ALONG A LINE 30.00 FEET WEST OF AND PARALLEL
TO THE EASTERLY LINE OF THE SOUTHWEST QUARTER (SW 1/4) OF THE SOUTHEAST QUARTER
(SE 1/4) OF SAID SOUTHWEST QUARTER (SW 1/4), 322.47 FEET TO A TANGENT 25.00 FEET
RADIUS CURVE;
THENCE ALONG SAID CURVE CONCAVE NORTHWESTERLY THROUGH A CENTRAL ANGLE OF
86(degree)21'59", AN ARC LENGTH OF 37.68 FEET TO A LINE 45.00 FEET NORTH OF AND
PARALLEL TO THE SOUTHERLY LINE OF THE SOUTHEAST QUARTER (SE 1/4) OF SAID
SOUTHWEST QUARTER (SW 1/4);
THENCE ALONG SAID LINE, SOUTH 87(degree)16'26" WEST, 569.11 FEET TO THE WESTERLY
LINE OF THE SOUTHEAST QUARTER (SE 1/4) OF SAID SOUTHWEST QUARTER (SW 1/4);
THENCE ALONG SAID WESTERLY LINE, NORTH 01(degree)05'30" EAST, 289.27 FEET TO THE
SOUTHEAST CORNER OF THE NORTHEAST QUARTER (NE 1/4) OF THE SOUTHEAST QUARTER (SE
1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF SAID SOUTHWEST QUARTER (SW 1/4);
THENCE ALONG THE SOUTHERLY LINE THEREOF, SOUTH 87(degree)13'31" WEST, 315.98
FEET TO THE SOUTHWEST CORNER OF THE NORTHEAST QUARTER (NE 1/4) OF THE SOUTHEAST
QUARTER (SE 1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF SAID SOUTHWEST QUARTER (SW
1/4);
THENCE ALONG THE WESTERLY LINE THEREOF, NORTH 01(degree)11'37" EAST, 668.84 FEET
TO THE POINT OF BEGINNING.
TOGETHER WITH THAT PORTION OF SAID SOUTH HALF (S 1/2) OF THE SOUTHWEST QUARTER
(SW 1/4) OF SECTION 01, TOWNSHIP 22 SOUTH, RANGE 60 EAST, M.D.M., CLARK COUNTY,
NEVADA, MORE PARTICULARLY DESCRIBED AS FOLLOWS:
BEGINNING AT THE AFOREMENTIONED "POINT A";
THENCE NORTH 00(degree)54'27" EAST, 40.08 FEET;
THENCE NORTH 87(degree)14'47" EAST, 526.77 FEET TO A POINT ON THE WESTERLY
RIGHT-OF-WAY LINE OF LINDELL ROAD AD DEDICATED BY THAT CERTAIN DOCUMENT RECORDED
MARCH 14, 2002 IN BOOK 20020314 OF OFFICIAL RECORDS AS INSTRUMENT NO. 00744 IN
THE CLARK COUNTY RECORDER'S OFFICE, CLARK COUNTY, NEVADA;
THENCE ALONG SAID RIGHT-OF-WAY LINE, SOUTH 15(degree)38'00" EAST, 116.43 FEET TO
THE BEGINNING OF A TANGENT CURVE HAVING A RADIUS OF 760.00 FEET;
THENCE CURVING TO THE RIGHT ALONG THE ARC OF ARC OF SAID CURVE, CONCAVE
SOUTHWESTERLY, THROUGH A CENTRAL ANGLE OF 16(degree)21'23", AN ARC LENGTH OF
216.96 FEET;
THENCE SOUTH 00(degree)43'23" WEST, 45.00 FEET;
THENCE DEPARTING SAID RIGHT-OF-WAY LINE, SOUTH 87(degree)15'37" WEST, 275.78
FEET TO THE SOUTHWEST CORNER OF THE NORTHEAST QUARTER (NE 1/4) OF THE SOUTHEAST
QUARTER (SE 1/4) OF THE SOUTHEAST QUARTER (SE 1/4) OF THE SOUTHWEST QUARTER (SW
1/4) OF SAID SECTION 01;
THENCE NORTH 00(degree)48'55" EAST, 334.50 FEET TO A POINT ON THE NORTH LINE OF
THE SOUTH HALF (S 1/2) OF THE SOUTHEAST QUARTER (SE 1/4) OF THE SOUTHWEST
QUARTER (SW 1/4) OF SAID SECTION 01;
THENCE ALONG SAID NORTH LINE, SOUTH 87(degree)14'47" WEST, 315.32 FEET TO THE
POINT OF BEGINNING.
CONTAINING: 15.94 ACRES OF LAND.
BASIS OF BEARINGS
THE EAST LINE OF THE NORTHEAST QUARTER (NE 1/4) OF THE NORTHEAST QUARTER (NE
1/4) OF SECTION 1, TOWNSHIP 22 SOUTH, RANGE 60 EAST, M.D.M., CLARK COUNTY,
NEVADA, AS SHOWN ON THAT MAP ON FILE IN
FILE 66 OF SURVEYS AT PAGE 02 OF OFFICIAL RECORDS, CLARK COUNTY, NEVADA, SAID
LINE BEARS NORTH 00(degree)42'44" WEST.
ROBERT M. MCENTEE
PROFESSIONAL LAND SURVEYOR
NEVADA CERTIFICATE NO. 12998
EXPIRES 12/31/07
LOCHSA SURVEYING
(702) 365-9312/FAX (702) 320-1769
EXHIBIT D
"HAZARDOUS MATERIAL" AND "STORAGE TANK" LIST
In addition to general office and cleaning supplies, the following (which may be
defined as "Hazardous Material" in the Lease) may be brought upon, treated,
kept, stored, generated, or used upon the Property:
Gasoline, diesel fuel and other petroleum hydrocarbons, including, but not
limited to, new and used oil, hydraulic fluid, brake fluid, transmission fluid,
gear oil, etc.
Polychlorinated biphenyls (PCBs), including PCB transformer oil, PCB
contaminated soil and PCB-contaminated debris.
Cleaning solvents.
Welding gases.
Antifreeze.
Aerosols, including paint, brake cleaner, WD-40, glass cleaner, etc.
Windshield washer fluid.
Steam cleaner soap.
Oils and greases.
New and used batteries, including those with lead and acid contents.
New and used transformer oil.
SF6 gas.
Water contaminated with oil and/or metals.
Asbestos.
Ampac shells and Caldwell cartridges containing gun powder and similar
substances.
Treated wood poles.
Paint.
Paint remover.
CFCs. Mercury.
Solvents.
Soil contaminated with any Hazardous Material identified above on this
Exhibit "D".
The following "Storage Tanks" and containment facilities will be located on the
Property:
One or more above-grade unleaded gasoline fuel tanks, each with a capacity
of 15,000 gallons or less.
One or more above-grade diesel fuel tanks, each with a capacity of 15,000
gallons or less.
Three or more above-grade vaulted tanks for new and used non-detect
transformer oils, each with a capacity of up to 3,000 gallons.
One or more above-grade tanks for used non-PCB mineral oil, each with a
capacity of up to 3,000 gallons.
One or more above-grade tanks for used PCB contaminated oil, each with a
capacity of up to 3,000 gallons.
One or more concrete pads and self-contained containment tanks in
transformer containment areas, including covered containment slabs and run-off
trenches.
Two or more above-grade multiple compartment tanks for new and used oil,
hydraulic fluids, transmission fluids and other petroleum hydrocarbons, each
tank with multiple compartments of up to 500 gallons and single tank capacity of
up to 1,000 gallons.
One or more sand/oil separators and associated tank systems.
One or more kitchen grease traps.
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
D-1
EXHIBIT G
MASTER LEASE
(Attached or provided separately to Tenant)
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
G-1
FIRST AMENDMENT TO LEASE AGREEMENT
THIS FIRST AMENDMENT TO LEASE AGREEMENT (the "First Amendment") is made and
entered this 20th day of June, 2006, by and between the COUNTY OF CLARK,
a political subdivision of the State of Nevada ("County"), and BELTWAY BUSINESS
PARK WAREHOUSE NO. 2, LLC, a Nevada limited liability company authorized to do
business in the State of Nevada ("Company").
RECITALS:
A. County and Company entered into that certain Lease Agreement, dated
November 15, 2005 (the "Lease"), wherein Company agreed to lease from County and
County agreed to lease to Company certain real property located in Clark County,
Nevada, which is depicted and more particularly described in the Lease (the
"Premises"). All terms used herein and not otherwise defined shall have the same
meaning as given to them in the Lease.
B. County and Company desire to amend the Lease, as provided below in this
Amendment.
NOW, THEREFORE, for and in consideration of the covenants and conditions
herein, County and Company hereby agree as follows:
AGREEMENT:
1. Enlargement of Premises. The size of the Premises is hereby enlarged to
include an additional tract of land (the "Additional Land"); accordingly, the
descriptions of the Premises set forth on Exhibit "D" to the Lease and on
Exhibit "A" to that certain Memorandum of Lease, dated November 15, 2005 (and
recorded with the official records of Clark County, Nevada on November 21, 2005
in Book 20051121 as Instrument No. 2760), are hereby superseded and replaced
with the description attached as Exhibit "A" to this First Amendment, which
includes the Additional Land. Consistent with the above modification to the
description of the Premises, the parties shall execute and record an appropriate
Amended and Restated Memorandum of Lease.
2. Condition Subsequent. The continued effectiveness of this First
Amendment is expressly conditioned on the execution and delivery, within one
hundred eighty (180) days following the date of this First Amendment, of a lease
agreement between Company, as landlord, and a third party, as tenant, for the
Additional Land (the "Condition Subsequent"). If the Condition Subsequent is
timely satisfied, Company shall promptly provide County with written notice of
the same. In the event the Condition Subsequent is not satisfied or waived by
Company within the time set forth above, this First Amendment shall be rendered
null and void and without further force or effect, and in such event County and
Company shall execute and deliver an instrument confirming the same. Any waiver
by Company of the Condition Subsequent must be in writing and received by County
on or before the expiration of the time set forth above, and in the event of
such timely waiver by Company, this First Amendment shall remain binding on
County and Company and remain in full force and effect.
-1-
3. Effect of Amendment. Except as modified by this First Amendment, the
Lease shall remain in full force and affect. As amended hereby, the Lease is
hereby ratified and confirmed in its entirety. In the event of a conflict
between the terms of the Lease and this First Amendment, this First Amendment
shall control.
4. Miscellaneous. This First Amendment embodies the entire agreement
between the parties relating to the subject matter contained herein. There are
no representations, promises, warranties, understandings or agreements, express
or implied or otherwise, except for those expressly referred to or set forth
herein or in the Lease. No modification of this First Amendment or the Lease
shall be binding unless evidenced by an Agreement in writing signed by both
County and Company. This First Amendment may be executed in counterparts, each
of which shall constitute an original, and all of which taken together shall
constitute one and the same instrument.
[intentionally left blank -- signature page to follow]
-2-
IN WITNESS WHEREOF, this First Amendment has been executed as of the date
first written above.
COUNTY:
CLARK COUNTY, NEVADA,
a political subdivision of the State of
Nevada
By:
Printed Name:
Its:
APPROVED AS TO FORM:
David Roger, District Attorney
By:
Name:
Deputy District Attorney
COMPANY:
BELTWAY BUSINESS PARK WAREHOUSE
NO. 2, LLC, a Nevada limited liability
company
By: MAJESTIC BELTWAY WAREHOUSE
BUILDINGS, LLC, a Delaware limited
liability company, its Manager
By: MAJESTIC REALTY CO., a California
corporation, Manager's Agent
By:
Printed Name:
Its:
By:
Printed Name:
Its:
By: THOMAS & MACK BELTWAY, L.L.C
a Nevada limited liability company,
its Manager
By:
Thomas A. Thomas, Manager
-3-
EXHIBIT A
TO
FIRST AMENDMENT TO LEASE
Description of Premises
(Attached)
LEGAL DESCRIPTION
FOR
APN 176-01-301-032, 176-01-401-007, 009, 010, 012, 013 & 014, 176-01-402-007
(THE OVERALL BOUNDARY WAREHOUSE 2)
APN 176-01-301-032 AND APN 176-01-401-013
THE SOUTH HALF (S 1/2) OF THE NORTHEAST QUARTER (NE 1/4) OF THE SOUTHWEST
QUARTER (SW 1/4) AND THE NORTH HALF (N 1/2) OF THE SOUTHEAST QUARTER (SE 1/4) OF
THE SOUTHWEST QUARTER (SW 1/4) OF SECTION 1, TOWNSHIP 22 SOUTH, RANGE 60 EAST,
M.D.M., IN THE COUNTY OF CLARK, STATE OF NEVADA.
EXCEPTING THEREFROM ALL THAT PORTION OF THE ABOVE DESCRIBED LAND WHICH LIES
EASTERLY OF THE WESTERLY RIGHT OF WAY OF LINDELL ROAD AS DESCRIBED IN DOCUMENT
RECORDED MARCH 14, 2002 AS BOOK/INSTRUMENT NO. 20030314:00744, OF OFFICIAL
RECORDS IN THE OFFICE OF THE COUNTY RECORDER OF CLARK, NEVADA.
APN 176-01-402-007
THE NORTHEAST QUARTER (NE 1/4) OF THE SOUTHEAST QUARTER (SE 1/4) OF THE
SOUTHEAST QUARTER (SE 1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF SECTION 1,
TOWNSHIP 22 SOUTH, RANGE 60 EAST, M.D.M. IN THE COUNTY OF CLARK, STATE OF
NEVADA.
EXCEPTING THEREFROM ALL THAT PORTION OF THE ABOVE DESCRIBED LAND WHICH LIES
EASTERLY OF THE WESTERLY RIGHT OF WAY OF LINDELL ROAD AS DESCRIBED IN DOCUMENT
RECORDED MARCH 14, 2002 AS BOOK/INSTRUMENT NO. 20030314:00743, OF OFFICIAL
RECORDS IN THE OFFICE OF THE COUNTY RECORDER OF CLARK, NEVADA.
APN 176-01-401-014
THE EAST HALF (E 1/2) OF THE SOUTHWEST QUARTER (SW 1/4) OF THE SOUTHEAST QUARTER
(SE 1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF SECTION 1, TOWNSHIP 22 SOUTH,
RANGE 60 EAST, M.D.M., IN THE COUNTY OF CLARK, STATE OF NEVADA.
EXCEPTING THEREFROM ALL THAT PORTION OF THE ABOVE DESCRIBED LAND WHICH LIES
SOUTHERLY OF THE NORTHERLY RIGHT OF WAY OF WARM SPRINGS ROAD AS DESCRIBED IN
DOCUMENT RECORDED JANUARY 28, 2000 AS BOOK/INSTRUMENT NO. 20000128:00910, OF
OFFICIAL RECORDS IN THE OFFICE OF THE COUNTY RECORDER OF CLARK, NEVADA.
APN 176-01-401-010 AND 176-01-401-012
THE WEST HALF (W 1/2) OF THE SOUTHWEST QUARTER (SW 1/4) OF THE SOUTHEAST QUARTER
(SE 1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF SECTION I, TOWNSHIP 22 SOUTH,
RANGE 60 EAST, M.D.M., IN THE COUNTY OF CLARK, STATE OF NEVADA.
APN 176-01-401-009
THE NORTHEAST QUARTER (NE 1/4) OF THE SOUTHEAST QUARTER (SE 1/4) OF THE
SOUTHWEST QUARTER (SW 1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF SECTION 1,
TOWNSHIP 22 SOUTH, RANGE 60 EAST, M.D.M. IN THE COUNTY OF CLARK, STATE OF
NEVADA.
APN 176-01-401-007
THE SOUTHEAST QUARTER (SE 1/4) OF THE NORTHEAST QUARTER (NE 1/4) OF THE
SOUTHWEST QUARTER (SW 1/4) OF THE SOUTHWEST QUARTER (SW 1/4) OF SECTION 1,
TOWNSHIP 22 SOUTH, RANGE 60 EAST, M.D.M. IN THE COUNTY OF CLARK, STATE OF
NEVADA.
OVERALL ACREAGE = 47.07 ACRES MORE OR LESS
PREPARED BY:
LOCHSA ENGINEERING
6345 SOUTH JONES BOULEVARD
SUITE 100
LAS VEGAS, NV 89118
KATHLEEN M. HAND
P.E. #16209
(FLOOR PLAN)
S-1402, CLOSURE CALCULATION, 05-18-0-2006, BEH
Parcel name: SUBJECT PROPERTY
North: 4396.3926 East: 1352.8021
Line course: N 87-20-5S E Length: 303.08
North: 4410.4128 East: 1655.5576
Line Course: N 87-20-55 E Length: 780.20
North: 4445.5040 East: 2434.9224
Line Course: S 01-08-44 W Length: 564.75
North: 3881-8669 East: 2423.6317
Line course: S 01-08-44 W Length: 16.54
North: 3865.3302 East: 2423.3010
Line course: S 01-08-44 W Length: 235.77
North: 3529.6073 East: 2418.5874
Curve Length: 245.99 Radius: 840.40
Delta: 16-46-44 Tangent: 123.33
chord: 245.11 Course: S 07-14-38 E
Course In: S 88-51-16 E Course Out: S 74-22-00 W
RP North: 3612.8137 East: 3258.4196
End North: 3386.4537 East: 2449.4941
Line Course: S 15-38-00 E Length: 251.32
North: 3144.4310 East: 2517.2199
Curve Length: 216,96 Radius: 760.00
Delta: 16-21-23 Tangent: 109.22
Chord: 216.22 Course: S 07-27-18 E
Course In: S 74-22-00 W Course Out: S 89-16-37 E
RP North: 2933.6261 East: 1785.3354
End North: 2930.0387 East: 2545.2739
Line Course: S 00-43-23 W Length: 45.00
North: 2S8S.0423 East: 2544.7060
Line Course: S 87-15-37 W Length: 275.78
North: 2871.8603 East: 2269.2412
Line Course: H 00-48-55 E Length: 334.50
North: 3206.3265 East: 2274.0008
Line Course: S 87-14-47 W Length: 315.32
North: 3191.1781 East: 1959.0448
Line Course: S 00-54-27 W Length: 618.81
North: 2572,4455 East: 1949.2440
Line Course: S 87-16-26 W Length: 316.31
North: 2557.4015 East: 1633.2920
Line Course: S 00-59-58 W Length: 50.11
North: 2507.2992 East: 1632.4179
Line Course: S S7-16-26 W Length: 316.39
North: 2492.2511 East: 1316.3860
Line Course: N 01-05-30 E Length: 334.37
North: 2826.5604 East: 1322.7564
Line Course: S 87-13-31 W Length: 315.98
North: 2811.2641 East: 1007.1469
Line Course: N 01-11-37 E Length: 334.42
North: 3145.6116 East: 1014.1131
Line Course: N 01-11-37 E Length: 334.42
North: 3479.9590 East: 1021.0794
Line Course: N 87-13-39 E Length: 314.79
North: 3495.1855 East: 1335.5010
Line Course: N 01-05-30 E Length: 317.84
North: 3812.9678 East: 1341.5565
Line Course: N 01-05-30 E Length: 16.54
North: 3829.5048 East: 1341.8716
Line Course: N 01-06-16 E Length: 567.00
North: 4396.3995 East: 1352.8005
|
Page 1
Perimeter: 7422.18 Area: 2,050,534 sq.ft. 47.074 ACRES
Mapcheck closure - (Uses listed courses and chords)
Error Closure: 0.0070 course: N 13-07-41 W
Error North: 0.00684 East: -0.00160
Precision 1: 1,060,081.43
LEASE AGREEMENT
THIS LEASE AGREEMENT (hereinafter referred to as "Agreement") entered into
this 15th day of November by and between the COUNTY OF CLARK, apolitical
subdivision of the State of Nevada (hereinafter referred to as "County") and
BELTWAY BUSINESS PARK WAREHOUSE NO.2, LLC, a Nevada limited liability company
authorized to do business in the State of Nevada (hereinafter referred to as
"Company").
WITNESSETH:
WHEREAS, County is the owner and operator of McCarran International Airport
(hereinafter referred to as "Airport") and wishes to cause the development and
construction of retail/office/warehouse facilities (hereinafter referred to as
"Commercial Facilities") on property owned by Clark County within the
Cooperative Management Area (defined below) and controlled by the Airport to
ensure that the development of such property is compatible with Airport uses;
and
WHEREAS, it is for the benefit of County to more efficiently and
economically manage its Airport-controlled property to include such Commercial
Facilities; and
WHEREAS, Company is engaged in the business of developing, constructing,
maintaining, leasing and operating such Commercial Facilities; and
WHEREAS, County is willing and Company desires to enter this Agreement for
the construction and operation of such Commercial Facilities; and
WHEREAS, on August 21, 2001 the Board of County Commissioners approved a
Lease Option Agreement (hereinafter referred to as "Lease Option Agreement")
between County and Beltway Business Park, L.L.C., an affiliate of Company, which
was first amended on March 5, 2002, and then amended on December 3, 2002, and
then amended on September 20, 2005; and
NOW, THEREFORE, for and in consideration of the above recitals (which are
incorporated into this Agreement by this reference), and the agreements,
covenants and conditions herein, County and Company agree as follows:
ARTICLE I
1.1 DEFINITIONS
1.1.1 The term "Airport," whenever used herein, means the McCarran
International Airport and all property located within its general
environs at the date of execution of this Agreement or at any future
date during the term hereof.
1.1.2 The term "Airport Environs Map," means the McCarran International
Airport Environs Overlay District map, prepared by the Department of
Aviation and dated April 16, I998, or any subsequent version of such
maps as may be updated from time to time by the Department of
Aviation.
1.1.3 The term "Approval Date" means the date upon which this Agreement is
approved by the Board of County Commissioners.
1.1.4 The term "Approved Budget," whenever used herein, means the annual
written budget prepared by Company and approved by County's Designated
Representative pursuant to the procedure set forth in Section 1.6
(entitled BUDGET APPROVAL) below.
1.1.5 The term "Assignee," whenever used herein, means (i) any assignee of
Lender's interest in the Loan, or (ii) any purchaser or any heir,
successor, or assign of the leasehold estate evidenced by this
Agreement that acquires such leasehold estate at or subsequent to a
Foreclosure Transfer (as defined in Section 2.19.11.1 below), as
approved by County, to the extent such approval is required pursuant
to Section 2.19.11.1 below, or (iii) any assignee of Company's rights
and duties under this Agreement pursuant to Section 2.1 (entitled
ASSIGNMENT) below.
1.1.6 The term "Capital Improvement Expenditures," whenever used herein,
means the expenses of a capital nature associated with the Commercial
Facilities which exceed those set forth in the Approved Budget. Such
expenses will require prior written approval of County's Designated
Representative.
1.1.7 The term "County's Designated Representative (hereinafter referred to
as 'CDR')," whenever used herein, means the Director of the Department
of Real Property Management, or designee, acting on behalf of County.
1.1.8 The term "Commence Construction," whenever used herein, means
commencing construction of the Commercial Facilities on the Premises
by Company causing its construction contractor to obtain occupancy and
control the area and to begin actual construction of the Commercial
Facilities. The term shall not include any site preparation or
off-site work related to the Premises.
1.1.9 The term "Commercial Facilities," whenever used herein, means the
retail/office/warehouse improvements to be constructed on the Premises
by Company in accordance with the terms and conditions of this
Agreement.
1.1.10 The term -"Company," whenever used herein, means. BELTWAY BUSINESS
PARK WAREHOUSE NO. 2, LLC, a Nevada limited liability company,
entering into this Agreement as the developer and operator of the
Commercial Facilities on the Premises as described herein.
1.1.11 The term "Cooperative Management Area" or "CMA," whenever used
herein, means the land area included within the Airport's 60 and above
day-night average decibel level noise contours, as defined in the 1992
Interim Cooperative Management Agreement between the U.S. Department
of Interior's Bureau of Land Management and County, a copy of which is
attached hereto as Exhibit "A" and incorporated herein (the "CMA
Agreement"). Only those land uses defined in the CMA Agreement as
compatible with Aircraft (defined below) operations will be permitted
on County-owned parcels within the CMA that were acquired by
-2-
County under the terms of Southern Nevada Public Land Management Act
of 1998 (the "SNPLMA" ), a copy of which is attached hereto as Exhibit
"B" and incorporated herein.
1.1.12 The term "County," whenever used herein, means Clark County, Nevada,
as represented by the Clark County Board of Commissioners and where
this Agreement speaks of "Approval by County," such approval means
action by the Clark County Board of Commissioners.
1.1.13 The term "Debt Service," whenever used herein, means the Company's
payment of principal and interest for construction and/or permanent
financing for Commercial Facilities.
All financing for Commercial Facilities shall include any fees,
including loan points, fees, closing costs, and other loan charges
(monthly or otherwise) to any Lender, including without limitation,
lending institutions or shareholders, officers, directors, members,
and managers of Company for construction and/or permanent financing
for Commercial Facilities. Except as otherwise approved in writing by
CDR, the principal loan amounts of such financing shall not exceed
100% of the "Pro Forma Development Costs" (as set forth in Exhibit "C"
attached hereto and incorporated herein) and shall not be amortized
over more than thirty (30) years. Any such financing must be approved
by CDR as outlined in Section 2.19.1 below, and shall be at
commercially reasonable interest rates, points, fees, closing costs,
and other terms and conditions for the same type of loan from a bank
or other commercial lender.
1.1.14 The term "Effective Date," whenever used herein, means the date
established pursuant to Sections 1.2.6 and 1.7 below for the
commencement of the distribution of Net Revenues (first, to repayment
of any equity contribution and second, for distribution to County and
Company as provided in Section 1:7 below). All other terms and
conditions of this Agreement will become effective on the Approval
Date.
1.1.15 The term "Environmental Laws," whenever used herein, means any one
or all of the laws and/or regulations of the Environmental
Protection-Agency or any other federal, state or local agencies,
including, but not limited to the following as the same are amended
from time to time:
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY
ACT (42 U.S.C. Section 9601 et seq.)
RESOURCE CONSERVATION AND RECOVERY ACT (42 U.S.C. Section 6901 et
seq.)
TOXIC SUBSTANCES CONTROL ACT (15 U.S.C. Section 2601 et seq.)
SAFE DRINKING WATER ACT (42 U.S.C. Section 300h et seq.)
-3-
CLEAN WATER ACT (33 U.S.C. Section 1251 et seq.)
CLEAN AIR ACT (42 U.S.C. Section 7401 et seq.)
NEVADA SANITATION LAWS (Nevada Revised Statutes, Chapter. 444)
NEVADA WATER CONTROL LAWS (Nevada Revised Statutes Chapter 445A)
NEVADA AIR POLLUTION LAWS (Nevada Revised Statutes Chapter 445B)
HAZARDOUS MATERIALS, INCLUDING UNDERGROUND STORAGE TANK
REGULATIONS (Nevada Revised Statutes, Chapter 459)
NEVADA OCCUPATIONAL SAFETY AND HEALTH ACT (Nevada Revised
Statutes, Chapter 618)
and the regulations promulgated thereunder and any other laws, regulations and
ordinances. (whether enacted by the Federal, State or local government) now in.
effect or hereinafter enacted that deal with the regulation or protection of the
environment (including, but not limited to, the ambient air procedures and
records detailing chlorofluorocarbons [CFC]), ambient air, ground water, surface
water and land use, including sub-strata land.
1.1.16 The term "Hazardous Material," whenever used herein, means the
definitions of hazardous substance, hazardous material, toxic
substance, regulated substance or solid waste as defined within the
following:
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY
ACT (42 U.S.C. Section 9601 et seq.)
RESOURCE CONSERVATION AND RECOVERY ACT (42 U.S.C. Section 6901 et
seq.)
HAZARDOUS MATERIALS TRANSPORTATION ACT (49 U.S.C. Section 5101 et
seq.) and all present or future regulations promulgated thereto
DEPARTMENT OF TRANSPORTATION HAZARDOUS MATERIALS TABLE (49 C.F.R.
Part 172) and amendments thereto
ENVIRONMENTAL PROTECTION AGENCY (40 C.F.R. Part 300 and
amendments thereto--including Appendices thereto)
-4-
HANDLING OF HAZARDOUS MATERIALS (including transportation of
Hazardous Materials by Motor Carriers) (Nevada Revised Statutes
459.700 through 459.780)
and all substances, materials and wastes that are, or that become, regulated
under, or that are classified-as hazardous or toxic under any environmental law,
whether such laws are Federal, State or local.
1.1.17 The term "Initial Improvements," whenever used herein, shall mean
completion of the site work and building shell for. (i) one hundred
percent (100%) of the proposed Commercial Facilities, if consisting of
two (2) or fewer commercial buildings; or (ii) not less than fifty
percent (50%) of the proposed Commercial Facilities, if consisting of
more than two (2) commercial buildings.
1.1.18 The term "Lender," whenever used herein, shall mean the provider of
construction or permanent financing (or any refinancing) to Company in
connection with the construction of the Commercial Facilities, which
financing arrangements are to be approved by CDR to the extent
required under Section 2.19 (entitled FINANCING) of this Agreement.
1.1.19 The "Loan," whenever used herein, shall mean a loan made by a Lender
to Company and secured by a mortgage or deed of trust encumbering the
leasehold estate evidenced by this Agreement
1.1.20 The term "Management Fee," whenever used herein, means a fee to be
deducted from Total Revenue in consideration of the expenses incurred
by Company or its property manager for the project administration of
the Commercial Facilities. It is understood and agreed that during the
term of this Agreement such fee is to be up to three percent (3%) (for
industrial space), up to four and one-half percent (4.5%) (for office
space), or up to five percent (5%) (for retail space) of the Total
Revenue received by Company from Sublessees or as otherwise negotiated
by County and Company: Such Management Fee shall include all
compensation and property management administration expenses of all
Commercial Facilities personnel. Such Management Fee may be adjusted
as necessary by mutual agreement of Company and CDR and as set forth
in an Approved Budget to be competitive with other fees that are
standard in the industry in the metropolitan area.
1.1.21 The term "Maintenance and Operations," whenever used herein, means
the expense for maintenance, operation, administration and repair of
the Commercial Facilities.
1.1.22 The term "Net Revenue," whenever used herein, means the amount of
available cash after allowable deductions have been made from Total
Revenue which is available for an equal fifty percent (50%)
distribution between the Participating Parties of this Agreement
Allowable deductions are defined as follows:
a. Debt Service;
-5-
b. Actual expenses authorized in the Approved Budget, including
the cost of any Maintenance and Operations, or other Project
Costs approved by CDR, which approval will not be
unreasonably withheld;
c. Capital Improvement Expenditures;
d. Management Fee;
e. A reasonable reserve for Maintenance and Operations or any
reserve required by any Lender under any approved financing;
and
f. Repayment of equity contribution plus return on equity
contribution Of applicable), as per Section 1.7 (entitled
RENTALS AND FEES) below.
1.1.23 The term "Participating Parties" or "Parties," whenever used herein,
means Company as Lessee and County as lessor (hereinafter jointly
referred to as "Parties") to a participating leasing arrangement for
the sharing of Net Revenues as consideration for the development and
operation of the commercial facilities at the Premises.
1.1.24 The term "Premises," whenever used herein, means that area depicted
on Exhibit "D," which is attached hereto and made a part hereof. The
final legal description of the Premises will be attached to the
Memorandum of Lease described in Section 1.2.3 below.
1.1.25 The term "Project Cost," whenever used herein, means all costs of
Company actually incurred and paid by Company in designing,
developing, constructing, owning, leasing, and managing the Commercial
Facilities.
1.1.26 The term "Sublease," whenever used herein, means the documents
signed by a Sublessee or Tenant for the leasing of space in the
Commercial Facilities.
1.1.27 The term "Sublessee" or "Tenant," whenever used herein, means any
business firm or individual who leases office, retail, industrial or
warehouse space for a valid, legal commercial activity in the
Commercial Facilities. Subject to the terms of Section 1.4.1 below,
the CDR will retain the right to reasonably approve the uses of such
Sublessee or Tenant. These defined terms may be used interchangeably.
1.1.28 The term "Release," whenever used herein, means any releasing,
spilling, leaking, pumping, pouring, emitting, emptying, discharging,
injecting, escaping, leaching, disposing or dumping of any Hazardous
Material in violation of Environmental Laws.
1.1.29 The term "Rent Commencement Date," whenever used herein, means the
date established pursuant to Sections 1.2.6 and 1.7 Below for the
commencement of
-6-
the distribution of Net Revenues. As used in this Agreement, the "Rent
Commencement Date" is synonymous with the "Effective Date."
1.1.30 The term "Total Revenue," whenever used herein, means the total
amount of all rents, charges, fees and/or other income collected by
Company from any use of the Commercial Facilities. Any space occupied
by Company or any related entity which is not exclusively used for the
necessary construction on and/or management of the Premises must be
charged at a similar rental rate to that being charged for a similar
type of rental property in the Las Vegas Valley. Such rental value
shall be' included in the Total Revenue, whether or not a cash payment
is made.
1.2 TERM
1.2.1 The term of this Agreement will expire fifty (50) years from the
Approval Date (the "Termination Date").
1.2.2 Except for Section 1.7 (entitled RENTALS AND FEES) below, all other
provisions of this Agreement will be in force and effect upon the
Approval Date.
1.2.3 As soon as practicable following the Approval Date, County and
Company agree to execute and acknowledge a Memorandum of Lease (1)
evidencing the existence of this Agreement, the ownership of the
Commercial Facilities by Company, the rights of Company in the
Premises, and the Approval Date and Termination Date of this
Agreement, and (2) containing a legal description of the Premises.
Such Memorandum of Lease shall be recorded with the official real
estate records of Clark County, Nevada.
1.2.4 As soon as practicable following the Approval Date, Company will be
entitled to receive, as a Project Cost, an ALTA leasehold policy of
title insurance, together with those endorsements reasonably deemed
necessary by Company, all issued by a title company. selected by
Company, with liability in an amount reasonably determined by Company
and insuring Company's interests hereunder. Such leasehold policy will
be subject only to exceptions permitted by Company.
1.2.5 County hereby agrees to give Lender at least thirty (30) days prior
notice of any intended amendment, modification, revocation,
surrender, cancellation or termination of this Agreement. County
further agrees that it will not consent to or accept any surrender,
revocation, cancellation or other termination by Company or amendment,
nor agree to any modification of this Agreement without Lender's prior
written approval. No expiration or early termination of this Agreement
shall terminate or extinguish this Agreement without the prior written
consent of Lender, unless the termination arises after a default and
Lender has been given the notice and cure rights specified under
Sections 2.15.2 and 2.19 of this Agreement, and has failed to cure in
accordance therewith.
-7-
1.2.6 Subject to Section 1.7 (entitled RENTALS AND FEES) below, the
Effective Date (also known as the Rent Commencement Date) will be the
first of the following dates:
1.2.6.1 The date of completion of the Initial Improvements for the
Commercial Facilities, as evidenced by County's issuance of a
Certificate of Completion.
1.2.6.2 The date that any portion of the Premises generates any
revenue or has a Temporary Certificate of Occupancy with actual
occupancy and use.
1.2.6.3 Subject to the extension rights set forth in Section 1.10.3.1
below, upon the first day of the thirty-sixth (36th) month
following the Approval Date.
1.3 PREMISES
1.3.1 County does hereby demise and let unto Company and Company does
hereby take from County the Premises.
Company shall be responsible to provide County with a final legal
description of the entire Premises under this Agreement, which
includes the depiction of all current and proposed easements and/or
rights-of-way that County has or may wish to retain. Company will
submit a draft description, both narrative and graphic formats, to
County for its review and County has the right to modify the documents
to retain County's interests in any easements and/or rights of way
necessary for roads, utilities, and flood control. Once a final legal
description is agreed upon by both parties, such legal description
will be included in the Memorandum of Lease, as provided in Section
1.2.3 above.
1.3.2 Company acknowledges that it has inspected the Premises and accepts
the Premises "as is," including, but not limited to, grades, soil
conditions, and drainage with no further responsibility to Company by
County for any present or further improvements or maintenance thereof,
including, but not limited to, the existence of any utilities and
public roadways and the potential need to cap off or otherwise abandon
such utilities and/or roadways.
1.3.3 All improvements constructed on the Premises by Company (including,
without limitation, the Commercial Facilities) at any time and from
time to time during the term will be owned by Company during the term
of this Agreement.
1.4 USE OF PREMISES
1.4.1 Upon performance of the agreements, provisions and conditions
contained in this Agreement, Company., will have the use of the
Premises for the construction and operation of Commercial Facilities
and for other business activities directly related thereto and for no
other purposes, unless approved in writing by CDR.
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Such Commercial Facilities uses will be for purposes similar to other
commercial developments in the Las Vegas metropolitan area and if such
uses are Compatible Uses (defined below) and not Incompatible Uses
(defined below), they are deemed approved by CDR. CDR, however,
retains the sole right to determine if a use is compatible with
Airport operations. Notwithstanding the above (or any other language
in this Agreement) to the contrary, the uses set forth in Exhibit "E"
attached hereto and incorporated herein shall be deemed approved by
CDR as Compatible Uses.
1.4.2 Neither Company nor County shall have the right to erect (or cause or
permit any third party to erect) billboards (whether for commercial or
non-commercial purposes) on the Premises.
1.4.3 Company also agrees that use of the Premises is conditioned upon
Company's agreement that it will not develop the Premises and/or
adjoining or surrounding properties in a manner that County may find
objectionable to Airport and/or Aircraft operations. CDR, however,
retains the sole right to determine, in its reasonable discretion, if
the uses are Incompatible Uses or Compatible Uses, as defined below:
1.4.3.1 Incompatible Uses: The term "Incompatible Uses" means uses
which potentially expose persons to elevated levels of Aircraft
generated noise or to areas identified as necessary to protect
the safe passage of Aircraft, or which have been determined by
the Federal Aviation Administration (the "FAA"), the Director of
the Department of Aviation, and/or the Airport Height Hazard
Board of Adjustment to be hazardous to or incompatible with air
navigation. Incompatible Uses include, but are not limited to:
rural estate uses, residential uses, single- family homes, mobile
homes, low density, medium density and high density housing,
apartments, group quarters, condominiums, time-sharing
apartments, condominium hotels or motels, townhouses, churches,
hospitals, care centers, nursing homes, schools, auditoriums and
concert halls, fraternity and sorority housing, recreational
vehicle parks, places of public assembly, amusement parks,
outdoor sports arenas, zoos, uses that may in the future be
accessory to or enhance any of the uses described above on
adjacent parcels, and uses intended to fulfill development and/or
zoning requirements for any of the uses described above on an
adjacent parcel (including, without limitation, open space,
parking and landscaping requirements). The fact that any of the
foregoing uses is permitted under the Clark County Code shall
have no bearing on whether they constitute an Incompatible Use
under this Restriction.
No "sexually oriented" business or "adult use," as defined in the
Clark County Code (e.g. CCC 6.110, 6.140, 6.160, 6.170, 7.54,
30.08.030, and 30.44.010 and as amended from time to time), or
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other laws, regulations and ordinances now in effect or
hereinafter enacted that deal with such businesses and uses,
shall be allowed upon any part of the Premises. No use for which
a liquor or gaming license is required shall be allowed upon any
part of the Premises without the written consent of County
(refusal to consent to these uses is solely within the discretion
of the Board of County Commissioners and does not need to be
reasonable). Should County consent to a use involving a liquor or
gaming license, Company shall pay all costs, including the cost
of background investigations and attorney fees, relating to the
licensing process. Notwithstanding the foregoing, CDR consents to
liquor uses, subject to all normal and customary licensing
procedures, in such restaurants as may be developed on the
Premises.
1.4.3.2 Compatible Uses: The term "Compatible Uses," means land uses
which are appropriate given the area's exposure to Aircraft
overflight and noise, and the limitations on development
necessary to preclude potential hazards to air navigation.
Compatible Uses which may conform with the preceding definition
include, but are not limited to, commercial uses such as office,
warehousing, manufacturing, business, professional, and wholesale
and retail, provided any occupied structure is constructed using
noise attenuation construction techniques in compliance with FAA
regulations as further outlined in Sections 1.4.3.3, 1.4.3.4 and
3.18 below; communication uses; transportation uses such as
railroad, motor vehicle, rapid transit and street railway
transportation; street and highway rights-of-way; utility
rights-of way; parking; general dispersed recreation; golf
courses; and drainage facilities.
1.4.3.3 Avigation Easement: Company hereby grants and conveys to
County a perpetual and assignable right-of-way and easement for
the free and unobstructed passage of all Aircraft,. regardless of
the owner or operator of such, in, through, and across all of the
airspace above the Premises (including the Commercial Facilities
constructed thereon) subject to such rights, terms, and
conditions as contained herein. For purposes of this Agreement,
"Aircraft" is defined as any contrivance now known or hereafter
invented, used, or designed for navigation of or flight in the
air or space, regardless of the form of propulsion which powers
said Aircraft in flight.
County, its successors in interest and assigns, for the use and
benefit of Aircraft owners, operators and the general public,
shall have the continuing right to cause or allow in all of the
airspace above the surface of the Premises such noise, fumes,
vibrations, dust, fuel, particles and all other effects that may
be caused by or
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result from the operation of Aircraft, whether or not said
Aircraft over fly or intrude into the airspace above the
Premises.
County reserves unto itself, its successors and assigns, for the
use and benefit of Aircraft owners, operators and the general
public, a right of flight for the passage of Aircraft in the
airspace above the Premises (including the Commercial Facilities
constructed thereon), together with the right to cause in said
airspace such noise as may be inherent in the operation of
Aircraft, now known or hereafter used; for navigation of or
flight in said airspace, and for use of said airspace for landing
at, taking off from or operating at the facilities now known as,
or any future name or common reference that may be promulgated,
adopted or referred to, McCarran International Airport, Nellis
Air Force Base, North Las Vegas Airport, Overton Airport, Indian
Springs Air. Force Base, Henderson Executive Airport,
Laughlin/Bullhead Airport, Searchlight Airport, Mesquite Airport,
Boulder City Airport, and Jean Airport; or any-and all. future
facility or facilities developed in the Ivanpah Valley, Pahrump
Valley, and in the vicinity of the City of Mesquite (the
"Airports").
Company covenants and agrees not to allow any improvement to
become constructed. on the Premises which is, will be or has been
erected to a height and does extend into the airspace where, upon
making application of a FAA form 7460-1 if required, the FAA
determines such improvement to- be an obstruction and/or hazard
to air navigation pursuant to the rules and regulations of the
FAA under Code of Federal Regulations ("CFR") Title 14, Chapter
I, Part 77 ("Part 77"). Should the FAA determine such proposed,
erected, or grown improvement to be an obstruction and/or hazard
to air navigation, the improvement is to be removed, demolished,
and/or lowered to a height which the FAA determines not to be an
obstruction and/or hazard to air navigation, and until such
compliance is determined by the FAA, Company shall not be granted
a permit under. Clark County Code Chapter 20 and Chapter 30,
including but not limited to Section 20.13 and Section 30.48 Part
B "Airport Airspace Overlay District" as amended, or any similar
federal state, or local regulation which may hereinafter be
enacted in total or in part:
Company covenants and agrees not to allow any vegetation to be
planted or grown on. the Premises which is, will be or has been
grown to a height and does extend into the airspace where, upon
making application of a FAA form 7460-I if required, the FAA
determines such vegetation to be an obstruction and/or hazard to
air navigation pursuant to the rules and regulations of the FAA
under Part 77. Should FAA determine such proposed or grown
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vegetation to be an obstruction and/or hazard to air navigation,
the vegetation is to be removed, trimmed, and/or lowered to a
height -which the FAA determines not to be an obstruction and/or
hazard to air navigation, and until such compliance is determined
by the FAA, Company shall not be granted a permit under Clark
County Code Chapter 20 and Chapter 30, including but not limited
to Section 20.13 and Section 30.48 Part B "Airport Airspace
Overlay District" as amended, or any similar federal state, or
local regulation which may hereinafter be enacted in total or in
part.
Company shall, prior to 1) construction of any applicable
improvement; 2) planting any applicable vegetation; or 3) at such
time as any vegetation is grown to a height on the Premises that
meets or exceeds the notification requirements of Part 77; file
notice with the FAA in accordance with the requirements of Part
77 as applied to the Airports via FAA form 7460-1, as amended, or
any similar regulations which may hereinafter be enacted and,
where required by the Clark County Code, receive either a
Director's Permit from the Department of Aviation or a Director's
Permit Variance from County's Airport Hazard Area Board of
Adjustment.
Company, in addition to all rights, terms, and conditions
contained herein, expressly acknowledges and consents to the
right of Aircraft flight set forth in Title 49 United States Code
("USC") Section 40102(a)(30), 49 USC Section 40103(a)(2), Title
14 CFR, Chapter I, Part 91., Part 101, and Part 103 as amended,
including but not limited to 14 CFR Part 91.119, or any similar
statute or regulation which may hereinafter be enacted in total
or in part, and Nevada Revised Statute ("NRS") Chapters,
including but not limited to, NRS 493.030, NRS 493.040 and NRS
493.050, as amended, or any similar regulation or statute which
may hereinafter be enacted in total or in part, as may be
undertaken by Aircraft arriving to or departing from the
Airports.
1.4.3.4 Waiver: Company, its successors, assigns, licensees, invitees,
and tenants, hereby waive, remise, and release any right, claim,
or cause of action which they may now have or may have in the
future against County, and its officers and employees, or
operators or users, and their officers, directors, employees, and
agents, of the above described Airports, for losses or
psychological or physical effects on account of or arising out of
noise, vibrations, fumes, dust, fuel, particles and all other
effects that may be caused or may have been caused by the
operation of Aircraft landing at, taking off from, or operating
at or on the Airports, or in or near the airspace above the
Premises. Company, its successors, assigns, licensees, invitees,
and tenants specifically waives any and all claims,
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including a claim that the easement is burdened by increases in
noise, fumes, vibrations, dust, fuel, particles, or any other
effects that may be caused by or result from the operation of
Aircraft; changes in the type or frequency of Aircraft
operations, the airport layout, or flight patterns; or increases
in nighttime operations.
Further, Company, its successors, assigns, licensees, invitees,
and tenants, hereby waive, remise, and release any right, claim,
or cause of action as to use and/or regulation of all airspace
more than fifty (50) feet above the finished grade of the
Premises (more than forty (40) feet above the finished grade will
require Airport and CDR written approval), except as may be
granted by County.
The above grant of Avigation Easement and Waiver do not require
the removal of an improvement or vegetation in the condition
existing on the Premises as of-the date of this Agreement.
Company expressly agrees for itself, its successors and assigns, to:
a. Submit to County plans showing exterior building finishes, including
but not limited to glass surfaces and exterior lighting, which
potentially may make it difficult for Aircraft pilots to distinguish,
between- airport lights and other lights; produce glare or reflection
which would impair Aircraft pilots landing or taking off at the
Airport, impair visibility in the vicinity of the Airport, or
otherwise endanger the landing, take off, or maneuvering of Aircraft;
and shall not install the same without receiving a Director's Permit
from the Department of Aviation or a variance from County's Airport
Height Hazard Board of Adjustment. Company shall not use, permit, or
suffer the use of the Premises in such manner a5 to create electrical
interference with radio communication to or from any Aircraft or
between any airport installation or navigational aid (NAVAID) and any
Aircraft.
b. Not authorize the construction of any facility or improvement on the
Premises, which attracts or results in the concentration of birds or
other wildlife which would interfere with the safe operation of
Aircraft in flight.
c. Use construction practices and materials to achieve an exterior to
interior noise level reduction sufficient to-achieve a maximum 40
decibel Day-Night Level (DNL 40 dB) interior noise level in any
permanent structures, based on Aircraft noise contours shown on the
McCarran International Airport Environs Overlay District Map, prepared
by the Department of Aviation and dated April 16, 1998, or on a
subsequent version of said map(s) as may be updated from time to time
by the Department of Aviation (Airport Environs Map). Land, buildings,
and structures shall be deemed to be impacted by the specific noise
contours that cross them as shown on the Airport Environs Maps. Where
a building is or would be
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impacted by one or more noise contours, the entire building shall be
considered to be within the most restrictive noise contour.
1.5 STANDARDS OF OPERATION
1.5.1 Company will develop and cause to be constructed Commercial
Facilities in accordance with - plans and specifications prepared by
Company and approved by CDR in order to provide a first-class
commercial facility operation for use by its Sublessees or Tenants.
1.5.2 Company may enter into a standard form Sublease (attached as Exhibit
"F' hereto and made a part hereof), which has been approved by CDR,
with Sublessees or Tenants. With CDR's approval, an entirely new form
of standard form. Sublease may be adopted for use by Company from time
to time.
1.5.2.1 Consistent with Section 2.2.1.4 below, Company must obtain the
written approval of CDR for any materially adverse change to the
standard form Sublease.
1.5.2.2 All Subleases must be for those uses permitted in Section I.4
(entitled USE OF PREMISES) above, and must incorporate by
reference all applicable provisions of this Agreement (as
reasonably determined by Company) to ensure every Sublessee's
operations and conduct are in compliance with such applicable
provisions of this Agreement.
1.5.3 Company will provide County with a copy of any rules, regulations or
other standards of operation developed by Company and distributed to
Sublessees and Tenants.
1.6 BUDGET APPROVAL
1.6.1 A written budget for each calendar year during the term of this
Agreement will be prepared for all expenses related to the use,
maintenance and operation of the Premises, including, without
limitation, maintenance, operation, administration, leasing and other
fees and expenses of any nature as follows:
1.6.1.1 On or within thirty (30) days following substantial completion
of the Commercial Facilities, Company and CDR will agree upon an
initial budget to cover the period from the Effective Date until
December 31 of the year in which the Effective Date falls.
1.6.1.2 By October 15, annually, Company will prepare and submit to
CDR a written budget for the following calendar year.
1.6.1.3 Within fourteen (14) days of receipt of the proposed budget,
CDR will review and approve or disapprove the proposed budget
submitted by Company.
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1.6.1.3.1 If disapproved on reasonable grounds, CDR will inform
Company in writing of its disapproval, describing the
disapproved provisions of the proposed budget, or requesting
further clarification of the budget elements. Company will
respond Within fourteen (14) days with clarification of the
budget elements or with a modified written budget, which is
reasonably satisfactory to CDR. The Participating Parties
agree to negotiate in good faith to resolve any conflicting
issues that may arise. If CDR fails to timely respond, the
proposed budget will be deemed approved and will become an
Approved Budget.
1.6.1.3.2 If, however, the Participating Parties cannot agree
upon the elements contained in the proposed budget or if,
during the term of the following year, the parties cannot
agree upon the interpretation of the intent of the Approved
Budget, a neutral third party will be selected by CDR to
arbitrate the disputed terms.
1.6.1.3.2.1 If, however, Company does not accept the neutral
third party selected by CDR, Company will be allowed to
select a second neutral party. The two selected parties
will then select a third neutral party and the three
together will arbitrate the disputed terms. County
agrees that Company may operate under the prior year
Approved Budget until the dispute is resolved. All
neutral parties shall have at least five (5) years
experience in commercial real estate matters and must
be attorney(s) certified by the Nevada Court Annexed
Arbitration Program.
1.6.1.3.2.2 CDR and Company agree to be bound by the
decisions reached by the selected arbitrator. The
Participating Parties will cause the arbitrator to make
a determination within fourteen (14) days following
submittal.
1.6.1.3.2.3 The Participating Parties agree that each party
will bear its own costs and expenses incurred for
attorney's fees, preparation and presentation costs for
the arbitration process. The Participating Parties will
share the cost of any third arbitrator.
1.6.1.4 The agreed upon budget will be deemed the Approved Budget for
the applicable calendar year. Until a budget has been approved,
the prior year's budget will be used.
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1.6.2 Company will be entitled to expend funds in accordance with the
Approved Budget during the applicable calendar year. In the event
Company is over-budget on a particular line item, Company may
reallocate excess funds from one line item to another line item,
except that any salary line item reallocations must be approved by
CDR. Any expenses not covered by the Approved Budget are subject to
the reasonable written approval of CDR. In the event of emergency,
Company may immediately take action necessary to complete repair and
any expenses incurred by Company will be shared in accordance with the
provisions of Section 1.7 (entitled RENTALS AND FEES) below.
1.7 RENTALS AND FEES
Rentals and fees for the operation of the Commercial Facilities will be as
follows:
1.7.1 As soon as practicable following the Approval Date, Company, at its
election, will obtain financing for the Commercial Facilities in
accordance with the, terms and conditions of Section 2.19 (entitled
FINANCING) of this Agreement. Rentals and fees will be subject to such
financing and completion, of the Commercial Facilities as follows:
1.7.1.1 The Participating Parties acknowledge that Company may be
required to make an equity contribution to fund the difference
between total Project Costs and the amount of financing obtained
by Company.
1.7.1.2 Following completion of the Commercial Facilities and once the
Net Revenue from the Commercial Facilities is available, such Net
Revenue will be applied to Company's equity contribution, if
applicable, until such time as the amount is repaid in full
together with interest at the rate of eleven percent (11%) per
annum. Company will furnish documentation satisfactory to CDR
showing the Total Revenues received from the Commercial
Facilities and the payments applied to the equity contribution
amount. Company shall not finance more than thirty percent (30%)
of Pro Forma Development Costs with its equity. Notwithstanding
the prior sentence to the contrary, if, following Company's
reasonable efforts to obtain loans requiring not more than thirty
percent (30%) equity, Company is unable to obtain such loans (on
reasonable and customary terms), then, Company will be allowed to
increase its equity contribution to such amounts required by its
Lenders. Except as otherwise agreed by County, any amount in
excess of thirty percent (30%) that is self-financed will be
repaid with interest at a rate equal to the applicable loan rate
(whether construction or permanent loan) plus one hundred fifty
(150) basis points per annum, not to exceed eleven percent (11%)
per annum.
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1.7.1.3 The Participating Parties will acknowledge the date the equity
contribution is paid in full by written notice from Company and
acknowledgment by CDR.
1.7.1.4 In the event of default by Company and the subsequent
foreclosure and sale of the leasehold interest to an Assignee as
provided in Section 2.19 (entitled FINANCING) below, and assuming
County declines the right to assume the Loan (as provided in
Section 2.19.11 below), the above defined rentals will be abated
as described in Section 2.19.11.2 below. Following satisfaction
of the Loan obligation owed to an Assignee of Lender, payment to
County of the rentals and fees as described in this Section 1.7
will resume.
1.7.1.5 Any additional capital required to be contributed for
operation of the Property, following completion of construction
of the Initial Improvements shall be contributed by Company, as
an additional equity contribution, provided such capital is
required to pay obligations arising under either an Approved
Budget or a Sublease, or reasonably required to remedy an
unforeseen situation. Any such equity contribution shall be
repaid as described in Section 1.7.1.2 above.
1.7.1.6 Company recognizes that the Premises are within the boundary
of the Cooperative Management Area and that this Agreement is
subject to the provisions of the SNPLMA, and that County is
required by the SNPLMA to receive "fair market value" for all
leases on land within the Cooperative Management Area. The
Parties agree and acknowledge that they have negotiated this
Agreement to be a fair market lease. If it is determined by a
court of competent jurisdiction that any of the terms and
conditions of this Agreement violate the SNPLMA, then Company
agrees to renegotiate in good faith the applicable terms of this
Agreement with County, consistent with the provisions of Section
4.6 below.
1.7.2 Upon the date Company's and County's equity contributions (if
applicable) are paid in full, with interest, as described in Section
1.7.1.2 above, the rental for the Premises will consist of County's
share of Net Revenue, as defined in Section 1.1 22 of this Agreement,
calculated as follows:
Total Revenue
Less: Debt Service
Actual expenses authorized in the. Approved Budget,
including the cost of any Maintenance and Operations,
development fees, leasing commissions,
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capital market fees, or other Project Costs approved by
CDR
Capital Improvement Expenditures
Management Fees
Reasonable reserves for Maintenance and Operations and
capital improvements, or any other reserve required by
any Lender under any approved financing
Equals: Net Revenue (available cash)
Distribution 50% to County
of Net Revenue: 50% to Company
1.7.3 On or before the twenty-fifth (25th) of each month, Company will
submit a statement depicting Total Revenue received for the preceding
month and allowable deductions for the Net Revenue calculation. A
check for County's fifty percent (50%) share of Net Revenue will be
submitted with such report.
1.7.4 Company will make all payments by check made payable to the Clark
County Department of Aviation and deliver or mail said payments to
County at McCarron International Airport, P.O. Box 11005, Las Vegas,
Nevada 89111-1005 or to such other place as County may direct Company
in writing:
1.7.5 In the event any required payment is not made by Company to County as
required and remains unpaid for a period of thirty (30) days or more,
County will be entitled to, and Company will pay to County, interest
at the rate of eleven percent (11%) per annum on all amounts unpaid
and which remain unpaid thirty (30) days past the due date. However,
the County will not be prevented from terminating this Agreement for
default of payments of rents, fees, or charges or from enforcing any
other provisions contained herein or implied by law.
1.7.6 On or prior to April 30, annually, during the term of this Agreement
or any extension thereof and within ninety (90) days after the
expiration of the term of this Agreement, Company will provide County
with a statement showing the entire preceding year's business
operations, including revenue and expenses, which will be prepared in
accordance with sound accounting principles. Such statement is to be
prepared by Company's Certified Public Accountant and contain a
written opinion as to whether the gross revenues and distribution of
Net Revenue has been made in accordance with the provisions of this
Agreement Should such statements show that the amount paid during the
period of review was less than that which was due, Company will
immediately remit the additional amount to County. Should such
statement show that Company paid County more than was due, after
review and verification by CDR a credit will be issued to be applied
against future Net Revenue, except that if such should be the case at
the
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end of the last month of this Agreement, County will refund the
overpayment to Company.
1.7.7 Subject to the extension rights set forth in Section 1.10.3.1 below,
if the Initial Improvements are not completed by the first day of the
thirty-sixth (36th) month following the Approval Date, then Company
will pay flat ground rent equal to the then fair market ground rent
for unimproved real estate which is: (a) subject to the same rights
and interests encumbering the Premises, and (b) at this location. Such
payment of flat ground rent shall continue only until the completion
of the Initial Improvements.
1.8 RECORDS AND AUDIT
1.8.1 Within forty-eight (48) hours of request by County, Company agrees to
provide at a location in the metropolitan area of Las Vegas, Nevada,
accurate books, records, and accounts of all revenues received from
Company's business authorized under this Agreement. Company further
agrees to make such books, records and accounts available at any time,
Monday through Friday (excluding holidays), 9:00 a.m. to 5:00 p.m. for
the inspection of CDR, or such agents, employees or accountants as
he/she may designate for at least a six (6) year period following the
end of each annual period of this Agreement. In the event that County
detects error(s) in fees in favor of County by a greater margin of one
percent (1%) during such inspection, the cost of the inspection shall
be borne by Company.
1.8.2 County will, at any time, have the right to cause an audit of the
business of Company to be made by a Certified Public Accountant of
County's selection and if the financial statements previously made to
County by Company will be found to be intentionally understated in any
respect or to be understated (either intentionally or unintentionally)
by a greater margin of one percent (1%) of Company's Total Revenue for
the period of review, then Company will immediately pay to County the
reasonable cost of such audit, as well as the additional payments
shown to be payable to County by Company. Otherwise, the cost of the
audit will be paid by County.
1.9 IMPROVEMENTS, MAINTENANCE AND REPAIR BY COUNTY
1.9.1 County has no direct responsibility or obligation for any
maintenance, repair or replacement 'of the leased Premises or
improvements.
1.9.2 In connection with the Commercial Facilities, at any time and from
time to time during the term of this Agreement, County agrees to, upon
the written request of Company, assist Company in delivering such
instruments as may be appropriate, necessary, required or desired by
Company for the purpose of (a) the grant or dedication of any
easement, right of way or other property right to any public entity or
service corporation or for the development of the Premises, so long as
such grant or dedication does not substantially impair the value of
the County's fee interest in the real property underlying the
Premises, or (b) the application to
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any governmental authority for, or the obtaining of, approvals;
consents, zoning changes, conditional uses, variances, subdivision
maps or the like, in each instance for the purpose of providing
adequate utility services to the Premises or of permitting Company to
construct the Commercial Facilities on the Premises or make any
alteration or addition to the Commercial Facilities, or (c) obtaining
institutional construction and permanent financing, including such
Estoppel Certificates, Subordination Agreements, and/or
Non-Disturbance and Attornment Agreements, in customary form, as may
be reasonably required by such Lenders.
1.10 IMPROVEMENTS, MAINTENANCE AND REPAIR BY COMPANY
1.10.1 In the operations of Company's activities within the Premises,
Company will design, develop; construct, manage and maintain and
repair the following:
1.10.1.1 All leasehold improvements, including but not limited to
grading, fencing, paving, lighting, roadways, parking lots,
drainage, structures, all applicable permits, zoning requirements
as required by Company for the operation of the Commercial
Facilities in the conduct of the business as authorized by
Section 1.4 (entitled USE OF PREMISES) of this Agreement.
Notwithstanding the assumption of any of these responsibilities
by a Sublessee, Company shall remain responsible to ensure all
leasehold improvements are completed in accordance with this
Agreement.
1.10.2 Commencement of construction of the Initial Improvements will be as
soon as all approvals are obtained following the Approval Date of this
Agreement.
1.10.2.1 If Company has not commenced construction by the nineteenth
(19'4) month after the Approval Date, it will be a material
breach of this Agreement and County will have the right of
termination as defined in Section 2.15 (entitled TERMINATION BY
COUNTY) of this Agreement. County agrees to give Company ninety
(90) days prior written notice before executing its right to
terminate this Agreement. County agrees not to exercise its right
to terminate until any Lender has been given its rights to cure
or foreclose on Company as provided in Section 2.19 (entitled
FINANCING) of this Agreement.
1.10.3 Subject to Section 1.10.3.1 below, the dare of completion of the
Initial Improvements. will be on or before the first (1st) day of the
thirty-sixth (36th) month following the Approval Date.
1.10.3.1 In the event the Initial Improvements are not completed
within such thirty-six (36) months due to circumstances beyond
the control of Company, County, through its CDR, may extend the
completion of the Initial Improvements deadline for a period not
to exceed six (6) months. In no event, however, will the
extension
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period be longer than the commensurate time affected by the
circumstances beyond the control of Company.
1.10.3.2 Should the deadline for completion of the Initial
Improvements not be extended as provided above or if the Initial
Improvements are not completed by the time frame allowed in such
extension, County may declare this failure to perform a material
breach of this Agreement and County will have the right to
terminate set forth in Section 2.15 (entitled TERMINATION BY
COUNTY) of this Agreement. County agrees to give Company ninety
(90) days prior written notice before executing its right to
terminate this Agreement. County agrees not to exercise its right
to terminate until any Lender has been given its rights to cure
or foreclose on Company as provided in Section 2.19 (entitled
FINANCING) below.
1.10.3.3 If, at the end of such thirty-six (36) months (as such period
may be extended as provided above), Company has not completed the
Initial Improvements proposed for the Premises, then Company
forfeits any rights to lease and develop the remaining
undeveloped portion of the Premises (the "Undeveloped Portion").
Upon ninety (90) days written notice to Company of its intent,
County will have the right to enter and occupy the Undeveloped
Portion. County agrees not to exercise this right until any
Lender has been given its rights to cure Company's default under
this Agreement or foreclose its mortgage or deed of trust, as
provided in Section 2.19 (entitled FINANCING) of this Agreement.
A modified Exhibit "D," excluding the Undeveloped Portion, will
then be prepared by Airport Engineering and verified by an
exchange of correspondence. Such modified Exhibit "D" will be
attached hereto and made a part hereof in replacement of the
current Exhibit "D" to this Agreement.
1.10.4 Company will construct and install the following, each of which will
be considered a Project Cost:
1.10.4.1 Underground utility lines and connections. Company's expense
will include all connection fees or all other fees.
1.10.4.2 All leasehold improvements including, but not limited to,
grading, fencing, paving, lighting, roadways, parking lots,
drainage and structures which are required by Company in its
conduct of business as authorized under Section 1.4 (entitled USE
OF PREMISES) below.
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1.10.5 Maintenance is understood and agreed to include all janitorial
services and requirements and daily routine Premises cleanup, and all
dust mitigation requirements.
1.10.6 All improvements or alterations by Company will be in accordance
with the Clark County Code and all other applicable governmental rules
and regulations. The shell drawings for the Initial Improvements are
also subject to the prior written approval of CDR; if requested by
CDR. In the event of a default hereunder by Company, Company will
provide County copies of all the following documents which are in
Company's possession: as-built drawings of all improvements, along
with a certification of construction costs for all permanent
improvements.
1.10.7 During the term or any extension of this Agreement, Company may, as
a Project Cost with -prior written approval of CDR, add to or alter
the Initial Improvements at any time subject to the applicable
provisions of this Section 1.10. Any such addition or alteration will
be performed in a workmanlike manner in accordance with all applicable
governmental regulations and requirements and will not weaken or
impair the structural strength or reduce the value of the Premises or
improvements thereon.
1.10.8 Company will be responsible as a Maintenance and Operation expense
for the removal and disposal of garbage, debris, contaminants and any
other waste material (whether solid or liquid) arising out of its
occupancy of the leased Premises or out of its operation. Such removal
will conform with all governmental requirements and regulations as
more fully described hereinafter in Section 3.22 (entitled
ENVIRONMENTAL POLICY) below.
1.10.9 Should Company fail to perform its maintenance and repair
responsibilities, County may, but is not obligated to, provide
maintenance and make repairs thereon and thereto, upon thirty (30)
days prior written notice of its intent to do so; except in case of
emergency for which no notice is necessary. Company shall reimburse
County for any such reasonable amounts as billed, plus a ten percent
(10%) administrative fee. Company may then charge such costs to the
project as a maintenance expense.
1.10.10 In addition to this Agreement, County may enter into other ground
lease agreements on substantially similar terms with affiliates of
Company (the "Company Affiliates") for the development of other real
property owned or controlled by County on or in the vicinity of the
Airport (the "Related Lease Agreements"). Notwithstanding any language
to the contrary contained in this Agreement, Company may, with CDR's
prior written consent, alter the boundary lines of the Premises under
this Agreement, and under the Related Lease Agreements, and reorder
the sequence and timing of the commencement of construction of the
Commercial Facilities under this Agreement and under the Related Lease
Agreements; provided, however, that in no event shall such altering
and/or reordering excuse Company or any of the Company Affiliates
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from fulfilling their obligations under this Agreement or under the
Related Lease Agreements.
1.10.11 The Company shall submit a site plan ("Site Plan") for the proposed
Premises, including all areas that have previously been the subject of
an exercise of the lease option granted in the Lease Option Agreement,
to the CDR no later than the final Approval Date of this Agreement by
the Board of County Commissioners. In addition, Company shall submit
an updated Site Plan in connection with any proposed amendment to this
Agreement.
1.11 CONSTRUCTION STANDARDS, RULES AND REGULATIONS
All Initial Improvements by Company will be in accordance with the Clark
County Code and all other applicable governmental rules and regulations.
Further, design and construction specifications and documents must be
reviewed by County Department of Building and Zoning prior to the issuance
of a building permit and will be subject to any statute, ordinance, rule or
regulation of any other applicable governmental agency, department or
authority whether Federal, State or local.
1.12 APPROVALS TO BE REASONABLY GIVEN
It is understood and agreed that all provisions of this Agreement which
require approval by or the consent of the County or CDR, except those that
are specifically noted as "sole" discretion (which still require responses
in a timely manner), will receive timely response and such approvals or
consents will not be unreasonably withheld, conditioned or delayed.
ARTICLE II
2.1 ASSIGNMENT
2.1.1 Company will not assign its rights or duties hereunder or any estate
created hereunder, in whole or in part, except with the prior written
consent of County. County agrees to provide such consent if the
proposed Assignee presented is a "proper and fit" person or entity,
which means one having (1) demonstrated experience in the management
of comparable commercial real estate properties (i.e., at least five
(5) years of such management experience or a contractual relationship
with a manager with such minimum experience), and (2) financial
resources sufficient, in County's reasonable business judgment, to be
financially secure to perform Company's obligations hereunder (i.e.,
having a net worth of at least Two Million Dollars ($2,000,000) as
increased annually according. to the percentage increase during the
preceding year in the Consumer Price index for all urban wage earners
and clerical workers [CPI-W] U.S. average all items prepared by the
Bureau of Labor Statistics of the United States Department of Labor,
with such increase not to exceed four percent (4%)). Further, any such
assignment will be specifically subject to all provisions of this
Agreement Except as provided below in this Section 2.1.1, any
assignment by Company without County's
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consent is void. Notwithstanding the above, if the proposed Assignee
is an institutional investor having a net worth of at least Twenty
Million Dollars ($20,000,000) or an entity owned or controlled,
directly or indirectly, by such an institutional investor, no prior
written consent of County is required, but County shall be provided
written notice of any such assignment within thirty (30).days
following its effective date.
2.1.1.1 Any voluntary transfer of fifty percent (50%) or more of
Company's equity interest will be deemed an assignment.
2.1.1.2 Before any assignment will become effective, the Assignee
will, by written instrument, assume and agree to be bound by the
terms and conditions of this Agreement during the remainder of
the term thereafter. When seeking consent to an assignment
hereunder, Company will submit a copy of the document or
instrument of assignment to County. Any assignment will not
release Company from its obligations under this Agreement arising
prior to the date of assignment.
2.1.1.3 Any transfers by the equity owners of Company or the equity
owners of the equity owners of Company to each other or to other
related parties for estate planning purposes will not be
considered an assignment hereunder. For purposes of this Section
2.1 (entitled ASSIGNMENT), "related parties" shall mean, in the
case of individuals, any persons related by blood or marriage
within the second degree of consanguinity, and in the case of
legal entities, entities that control, are controlled by or are
under common control with each other. Company shall notify CDR,
in writing, of any such actions.
2.2 SUBLEASING
Company Will not sublease, rent to, or permit any persons, firms or
corporations to occupy any part of the leased Premises without having first
complied with the following terms and conditions:
2.2.1 Any arrangements must be in the form of a written instrument and must
be specifically for purposes and uses of the Premises as authorized
under this Agreement and subject to the provisions of this Agreement.
2.2.1.1 Consistent with Section 1.5.2 above, all Subleases are to be
entered into using the standard form agreement approved by CDR;
provided, however, that in the course of negotiating the final
terms of a particular Sublease, Company may make commercially
reasonable revisions and modifications to the standard form
agreement as required to consummate the transaction, subject to
the terms of Section 2.2.1.4 below.
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2.2.1.2 Any arrangements for the leasing of space which are not based
on the use of the standard form agreement approved in accordance
with Section 1.12 above must receive the prior written approval
of CDR.
2.2.1.3 All license agreements of Company shall be entered into using
a standard form of license agreement approved by-County;
provided, however, that in the course of negotiating the
final-terms of a particular license agreement, Company may make
commercially reasonable revisions and modifications to the
approved form of agreement as required to consummate the
transaction, subject to the terms of Section 22.1.4 below.
2.2.1.4 CDR must approve any materially adverse change to the standard
form of Sublease or license agreement. For purposes of this
Section 2.2.1.4, the term "materially adverse change" shall mean
any change to the form of Sublease attached hereto (or the
approved form of license agreement) that would amend those
provisions (a) dealing with the obligations of a Sublessee (or
licensee) to comply with the pertinent provisions of this
Agreement, or (b) which incorporate by reference any of the terms
and provisions of this Agreement.
2.2.2 All Subleases and license agreements of Company will be subject to
all terms and conditions of this Agreement.
2.3 ATTORNMENT
2.3.1 In the event Company ceases to be a party to this Agreement and
perform its obligations hereunder to County, other than by a transfer
of interest and novation approved in writing by County, all Sublessees
will recognize County as the successor to Company, and render
performance hereunder to County as if the Sublease were executed
directly between County and the Sublessees; provided, however, County
agrees that so long as Sublessees are not in default, County agrees to
provide quiet enjoyment to the Sublessees and County agrees to be
bound by all of the terms and conditions of such Sublease. County
shall execute a separate Subordination, Non-Disturbance and Attornment
Agreement if so required by any Sublessee.
2.3.2 All Subleases of Company will provide that:
If by reason of a default on the part of Company as lessee in the
performance of the terms of the provisions of the underlying
Agreement, the underlying Agreement and the leasehold estate of
Company as lessee thereunder is terminated by summary proceedings or
otherwise in accordance with the terms of the underlying Agreement,
all Sublessees will attorn to County and recognize County as lessor,
provided, however, County agrees that so long as such
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Sublessees are not in default, County agrees to provide quiet
enjoyment to the Sublessees and to be bound by all the terms and
conditions of such Sublease.
2.3.3 In the event this Agreement is terminated for any reason, all
Sublessees will be liable to County for their payment of rents and
fees.
2.4 SUCCESSORS AND ASSIGNS
All covenants and conditions of this Agreement will extend to and bind the
legal representatives, successors and assigns of the respective parties
hereto and all agreements with Assignees will include all provisions
contained in this Agreement.
2.5 CONTROL OF PERSONNEL
Company will, in and about the leased Premises, exercise reasonable control
over the conduct, demeanor and appearance of its employees, agents and
representatives and the conduct of its contractors and suppliers. Upon
objection from CDR to Company concerning the conduct, demeanor or
appearance of such persons, Company will, within a reasonable time, remedy
the cause of the objection.
2.6 SIGNS AND/OR WORKS OF ART
2.6.1 Company will not erect, install, operate, nor cause or permit to. be
erected, installed, or operated upon Airport property (other than the
Premises), any signs or other similar advertising devices for its own
business.
2.6.2 Any identifying signs erected, installed, operated or attached to the
leased Premises will require the prior written approval of CDR, which
will not be unreasonably withheld. Such approval may consider and
provide conditions concerning factors including, but not limited to,
size, type, content, and method of installation.
2.6.3 Company will not commission, install or display any work of art
without the prior written approval of CDR and without a full written
waiver by the artist of all rights under the Visual Arts Rights Act of
1990, 17 U.S.C. Sections 106A and 113.
2.7 ENTRY AND INSPECTION OF PREMISES
County, its authorized officers, employees, agents, contractors,
subcontractors or other representatives will have the right to enter upon
the Premises for the following reasons by providing at least two (2)
business days prior written notice and while accompanied by a
representative of Company (except in an emergency, in which case County
will provide concurrent or reasonable subsequent notice specifying the
nature of the emergency and the need for immediate entry).
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2.7.1 To inspect at reasonable intervals during regular business hours (or
any time in case of emergency) to determine whether Company has
complied and is complying with the terms and conditions of this
Agreement.
2.7.2 For the purpose of inspecting the Premises and for fulfilling
County's obligations hereunder, provided however, that such entry will
be at such times and in such manner as to not unreasonably interfere
with the operations of Company or its Sublessees. County may, however,
enter at any time for emergency repairs or maintenance without
responsibility to Company for loss of business.
No such entry by or on behalf of County upon the Premises will cause
or constitute a termination of this Agreement nor be deemed to
constitute an interference with the possession thereof nor constitute
a revocation of or interference with any of Company's rights in
respect thereof for exclusive use of the Leased Premises.
The inspections contemplated by the parties to this Agreement,
pursuant to this Section, are for the sole benefit of the parties. No
benefit to any third party is contemplated nor intended.
2.8 INTENTION OF PARTIES
This Agreement is intended solely for the benefit of County and Company and
is not intended to benefit, either directly or indirectly, any third party
or member(s) of the public at large, except for those provisions of this
Agreement specifically applicable to and for the benefit of a Lender. Any
work done or inspection of the Premises by County is solely for the benefit
of County and Company.
2.9 LIENS
Company shall prepare for County, in a manner required by law, a Notice of
Non-Responsibility. Company shall post in a conspicuous location on the
Premises a Notice of Non-Responsibility for the benefit of County. Company
will cause to be removed any and all liens of any nature including, but not
limited to, tax liens and liens arising out of or because of any
construction or installation performed by or on behalf of Company or any of
its contractors or subcontractors upon Company's leased Premises or arising
out of or because of the performance of any work or labor to it or them at
the Premises or the furnishing of any materials to it or them for use at
the Premises. Should any such lien be made or filed, Company will bond
against or discharge the same within thirty (30) days after written request
by CDR. The cost of bonding against or discharging any Liens relating to
construction or installation of Commercial Facilities shall be a Project
Cost.
Should Company or any Sublessee cause any improvements to the Premises,
Company shall cause any contract with any contractor, designer, or other
person providing work, labor, or materials to the Premises to include the
following clause:
Contractor agrees on behalf of itself, its subcontractors, suppliers
and consultants and their employees that there is no legal right to
file a lien upon County-owned
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property and will not file a mechanic's lien or otherwise assert any
claim against County's real estate or any County's leasehold interest
on account of any work done, labor performed or materials furnished
under this contract. Contractor agrees to indemnify, defend and hold
the County and Company harmless from any liens filed upon the County's
property and County's leasehold interest and shall promptly take all
necessary legal action to ensure the removal of any such lien at
Contractor's sole cost.
2.10 TAXES, LICENSES AND PERMITS
Company will promptly, as a Project Cost, pay all taxes, excises, license
fees and permit fees of whatever nature applicable to its operation and
lease of Premises hereunder, including any real property taxes. Company
shall not be responsible for any of County's franchise, inheritance, income
or other tax levied on County or County's right to receive income from the
Premises. Company may elect, however, at its own cost and expense to
contest any such tax, excise, levy or assessment. Company will keep current
municipal, state or local licenses or permits required for the conduct of
its business.
2.11 INDEMNITY
Company agrees to indemnify and hold County forever harmless from and
against all liability, loss, demand, judgments or other expense (including,
but not limited to, defense costs, expenses and reasonable attorney fees)
imposed upon County by reason of injuries or death of persons (including
wrongful death) and damages to property caused during and because of
Company's use or occupancy of Airport property or the leased Premises or
any actions or non-actions of Company, its officers, employees, agents, or
other representatives, including movement of vehicles, provided, however,
that such indemnity will not apply as to any negligent act or omission of
County, its employees, agents or representatives.
2.12 INSURANCE AND BONDS
2.12.1 Bonds
2.12.1.1 County shall waive the requirement for Company's general
contractor to furnish Bonds unless County provides reasonable
evidence that such. general contractor(s) does not possess the
financial ability or experience/reputation to complete the
faithful performance of the construction of the tenant
improvements or installation of equipment. Otherwise, Company
will require its general contractor to furnish Bonds covering the
faithful performance of the construction of the tenant
improvements or installation of equipment, payment of all
obligations arising thereunder to take effect upon completion of
the project, in such a form and amount as CDR may approve. Bonds
may be secured through the Contractor's usual sources provided
the Surety is authorized and licensed to do business in the State
of Nevada.
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Company will be allowed to name any Lender as an additional
obligee under any such bond.
2.12.1.2 If required by Section 2.12.1.1 above, prior to execution of
a construction contract, and not later than ten (10) calendar
days after notification of award, Company will require its
contractor to furnish the following Bonds to CDR:
a. Labor and Material Payment Bond in the amount of one hundred
percent (100%) of the contract price.
b. Payment and Performance Bond in the amount of one hundred
percent (100%) of the contract price.
CDR may waive or modify the requirements of this Section 2.12.1
upon written request by Company.
2.12.1.3 The Bonds referred to in Section 2.12.1.1 and 2.12.1.2 above
will be written on the Payment and Performance Bond and Labor and
Material Payment Bond forms approved by CDR.
2.12.1.4 Company will require its contractor to require the
attorney-in-fact who executes the required Bonds on behalf of the
Surety to affix thereto a certified and current copy of his power
of attorney.
2.12.1.5 Any Labor and Material Payment Bond, Performance Bond, or
Guaranty Bond prepared by a licensed nonresident agent must be
countersigned by a resident agent as per the provisions of N.R.S.
680A.300.
2.12.2 Insurance
2.12.2.1 Prior to the commencement of any improvement or equipment
installation on or about the Premises, Company will require that
its construction contractor procure and maintain insurance for
such construction and installation protecting both Company and
County as well as the construction contractor. Such insurance
will provide coverage and limits as are determined customary in
the industry by CDR and Company. Such insurance will include, but
is not limited to:
- General Liability on an "occurrence" basis only
- Automobile Liability
- Builder's Risk equal to the maximum probable loss covering
the project and all materials and equipment.
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2.12.2.2 Company's (or its Contractor's) insurance will be primary as
respects County' and Company, their officers, employees and
volunteers acting as agents of County (hereinafter referred to as
"volunteers"). Any other coverage available to County, its
officers, employees and volunteers will be excess over the
insurance required by the contract and shall not contribute with
in
2.12.2.3 Company will maintain worker's compensation in the amounts
and form as required by the Nevada Industrial Insurance Act and
the Nevada Occupational Diseases Act. Certificates evidencing the
valid, effective' insurance policies will be provided to and kept
on file with CDR.
2.12.2.4 Company will keep insured with responsible insurance
underwriters any improvements constructed by it upon and within
the leased Premises to the extent of not less than one hundred
percent (100%) of the full replacement cost of such improvements
using the "all risk" form of protection (or comparable coverage)
as acceptable to CDR. Company will be responsible for insuring
against any rental protection resulting in loss of income or
extra expense to Company.
2.12.2.5 Company will obtain and keep in full force and effect a
policy(s) of general liability on an "occurrence" basis only and
not "claims made." The coverage must be provided either on ISO
Commercial General Liability form, an ISO Broad Form
Comprehensive General Liability form, or equivalent, approved by
CDR and Company. Any exceptions to coverage must be fully
disclosed on the required Certificate. If other than these forms
are submitted as evidence of compliance, complete copies of such
policy forms will be. submitted to CDR within ten (10) days after
notice to Company. Policies must include, but need not be limited
to, coverages for bodily injury, property damage, personal
injury, Broad Form property damage, premises and operations,
severability of interest, products and completed operations,
contractual and independent contractors, with no exclusions of
coverage for liability resulting from the hazards of explosion,
collapse, and underground property damage.
Company will maintain limits of no less than One Million Dollars
($1,000,000) combined single limit per occurrence for bodily
injury (including death), personal injury and property damage.
2.12.2.6 Company will furnish Automobile Liability coverage for claims
for damage because of bodily injury or death of any person, or
property damage arising out of the ownership, maintenance or use
of any motor vehicles whether owned, hired or non-owned.
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Company will maintain limits of no less than One Million Dollars
($1,000,000) combined single limit "per accident" for bodily
injury and property damage.
2.12.2.7 All required insurance coverage as stated in this Section
2.12.2 will be evidenced by a current Certificate(s) of
Insurance. Such Certificates will include, but will not be
limited to, the following:
2.12.2.7.1 All Certificates. for each insurance policy are to be
signed by a person authorized by that insurer and licensed
by the State of Nevada.
2.12.2.7.2 Each insurance company's rating as shown in the latest
Best's Key Rating Guide will be fully disclosed and entered
on the required Certificates of Insurance. If the insurance
company providing the coverage has a Best rating of less
than A-NM, the adequacy of the insurance supplied by Company
(or its contractor), including the rating and financial
health of each insurance company providing coverage, is
subject to the approval by CDR. Such approval will not be
unreasonably withheld.
2.12.2.7.3 Company (or its contractor) will furnish renewal
Certificates for the required insurance during the period of
coverage required by this Agreement_ Company (or its
contractor) will furnish renewal Certificates for the same
minimum coverages as required in this Agreement. If such
certificate(s) are not provided in a timely manner, CDR may
declare Company (or its contractor) in default of its
obligation under this paragraph, subject to the cure rights
contained in Sections 2.15.2 and 2.19 below.
2.12.2.7.4 County, its officers, employees and volunteers must be
covered as additional insureds with respect to liability
arising out of the activities by or on behalf of the named
insured in connection with this Agreement. All property
insurance policies will contain a waiver of subrogation
clause in favor of Clark County.
2.12.2.7.5 Each insurance policy supplied by Company (or its
contractor) must be endorsed to provide that the amount of
coverage afforded to County by the terms of this Agreement
will not be suspended, voided, canceled or reduced in
coverage or in limits except after thirty (30) days' prior
written notice by mail.
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2.12.2.7.6 Any deductible, as it relates to coverage provided
under this Agreement, will be fully disclosed on the
Certificates of Insurance. Any deductible provided will be
reasonable and customary for this type of risk.
2.12.2.7.7 If aggregate limits are imposed on the insurance
coverage, then the amounts of such limits must be not less
than Two Million Dollars ($2,000,000) per occurrence or per
accident. All aggregates must be fully disclosed and the
amount entered on the required certificate of insurance.
Company's insurer must notify CDR of any erosion of the
aggregate limits. The "per occurrence" limits of insurance
required herein must be maintained in full, irrespective of
any erosion of aggregate. A modification of the aggregation
limitation may be permitted if it is deemed necessary and
approved by CDR and Company.
2.12.2.8 If Company fails to maintain any of the insurance coverages
required herein, then County will have the option to declare
Company in breach, subject to the cure rights contained in
Sections 2.15.2 and 2.19 below, or CDR may purchase replacement
insurance or pay the premiums that are due on existing policies
in order that the required coverages may be maintained. Company
is responsible for any expenses paid by County to maintain such
insurance and County may collect the same from Company.
2.12.2.9 The insurance requirements specified herein do not relieve
the Company (or its contractor) of its responsibility or limit
the amount of its liability to the County or other persons and
the Company is encouraged to purchase such additional insurance
as it deems necessary.
2.12.2.10 Company (or its contractor) is responsible for and must
remedy all damage or loss to any property, including property of
County, caused in whole or in part by Company or its contractor,
any subcontractor or anyone employed, directed or supervised by
Company. Company is responsible for initiating, maintaining, and
supervising all safety precautions and programs in connection
with this Agreement.
2.12.2.11 The minimum insurance limits set forth in this Section
2.12.2 are sufficient as of the anticipated Approval Date. It is
understood that due to the effect of inflation and/or other
factors, it may be necessary for County to raise the minimum
insurance limits to protect its interests. Company hereby agrees
to maintain such insurance limits as may be reasonably required
by County under the terms of this Agreement; provided, however,
that any increases
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in limits will not exceed the average increase within the
insurance industry in the State of Nevada for comparable
insurance coverage.
2.13 FIRE PROTECTION
From time to time and as often as reasonably required by County, Company
will conduct appropriate tests of any fire extinguishing apparatus located
on the Premises. Company or its Sublessees will keep in proper functioning
order all fire fighting equipment located on the Premises.
2.14 DAMAGE AND DESTRUCTION
In the event of damage, destruction, or substantial loss which materially
impairs Company's ability to operate or loss to any improvements
constructed upon the Premises, by any cause, which damage, destruction or
loss is not capable of being repaired within sixty (60) days, Company will
have the option to terminate this Agreement- which option will be
exercisable by written notice to County within ninety (90) days after the
occurrence of such event. Any such termination by Company shall require the
prior written consent of any Lender. In the event Company elects to
terminate this Agreement based upon such damage, destruction, or
substantial loss and Company or its employees or agents cause such damage,
destruction or substantial loss to occur, Company will be liable for and
will pay for all cleanup or demolition of the Premises necessary to make
the Premises ready for repair, replacement, restoration or rebuilding which
is not otherwise covered by insurance. In the event Company does not
exercise such option, or in the event said damage, destruction or loss is
capable of being repaired within sixty (60) days, then Company will
promptly repair, replace, restore or rebuild said improvements.
2.15 TERMINATION BY COUNTY
2.15.1 Default by Company
Company will be considered in default as Lessee under this Agreement
in the event of any one or more of the following occurrences:
2.15.1.1 The liquidation under federal bankruptcy statutes which
causes the discontinuance of the fulfillment of any required
provision of this Agreement by Company.
2.15.1.2 Company fails to pay the rental charges or other money
payments required by this Agreement when the same are due and the
continuance of such failure for a period of ten (10) days after
written notice thereof from CDR to Company.
2.15.1.3 Company voluntarily abandons any of the Premises leased or
assigned to it or discontinues the conduct and operation of its
business at the Premises.
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2.15.1.4 Company will be considered in default of this Agreement if
Company fails to fulfill any of the other terms, covenants, or
conditions set forth in this Agreement if such failure continues
for a period of more than thirty (30) days unless cured as
provided below.
2.15.2 Cure
Company will be considered in default of this Agreement if Company
fails to fulfill any of the terms, covenants, or conditions set forth
in this Agreement if such failure continues for a period of more than
thirty (30) days (except failure to pay rental charges as described in
2.15.1.2 above) after delivery by CDR of a written notice of such
breach or default, except if the fulfillment of its obligation
requires activity over a period of time, and Company will have
commenced in good faith to perform whatever may be required for
fulfillment within ten (10) days after receipt of notice and continues
such performance without interruption except for causes beyond its
control.
2.15.3 Termination For Default By Company
Subject to the lender protection provisions of Section 2.19 (entitled
FINANCING) below, if default is made by Company as described in
Section 2.15.1 or 2.15.2 hereinabove, and such default is not cured as
provided in such sections, County may elect to terminate this
Agreement with thirty (30) days' written notice to Company.
2.15.3.1 If County elects to terminate this Agreement, it will in no
way prejudice the right of action for rental arrearages owed by
Company.
2.15.3.2 In the event of any termination for default by Company,
County will have the right to enter upon the Premises and take
possession of same. Redelivery and disposal of improvements will
be as described in Section 2.18 (entitled REDELIVERY AND DISPOSAL
OF IMPROVEMENTS AT TERMINATION) of this Agreement.
2.16 TERMINATION BY COMPANY
2.16.1 Default By County
County will be considered in default as lessor under this Agreement if
County fails to fulfill any of the terms, covenants or conditions set
forth in this Agreement if such failure shall continue for a period of
more than thirty (30) days after delivery by Company of a written
notice of such breach or default.
2.16.2 Cure
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County will not, however, be considered in breach of this Agreement if
the fulfillment of its obligation requires activity over a period of
time and County has commenced in good faith to perform whatever may be
required for fulfillment within ten (10) days after receipt of notice
and continues such performance without interruption except for causes
beyond its control.
2.16.3 Termination For Default By County
If default is made by County as described in Section 2.16.1 above,
Company may elect to terminate this Agreement with thirty (30) days'
written notice to County.
2.16.3.1 In the event of the termination for default by County,
redelivery and disposal of improvements will be as described in
Section 2.18 (entitled REDELIVERY AND DISPOSAL OF IMPROVEMENTS AT
TERMINATION) of this Agreement.
2.16.3.2 In the event of any termination for default by County, it
will in no way prejudice the right of action for rental
arrearages owed by Company.
2.16.3.3 Company reserves the rights to any remedies it may have at
law or in equity arising from County's breach of this Agreement.
2.17 WAIVERS AND ACCEPTANCE OF FEES
2.17.1 No waiver of default by either party hereto of any of the terms,
covenants or conditions hereof to be performed, kept or observed will
be construed to be or act as a waiver of any subsequent default of any
of the terms, covenants, conditions herein contained to be performed,
kept and observed. Neither party hereto may waive any provisions
regarding Lender's rights without such Lender's prior written consent.
2.17.2 No acceptance of fees or other money payments in whole or in part
for any period or periods during or after default of any of the terms,
conditions or covenants to be performed, kept or observed by Company
will be deemed a waiver on the part of County of its right to
terminate this Agreement on account of such default.
2.17.3 Subject to the cure rights contained in Section 2.15.2 above and in
Section 2.19 below, no acceptance of fees or other money payments in
whole or in part for any period or periods during or after default of
any of the terms, conditions or covenants to be performed, kept or
observed by County will be deemed a waiver on the part of Company of
its right to terminate this Agreement on account of such default
2.18 REDELIVERY AND DISPOSAL OF IMPROVEMENTS AT TERMINATION
2.18.1 Company covenants that at the termination of this Agreement,
howsoever caused, it will quit and surrender such leased Premises in
good repair and condition,
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excepting reasonable wear and tear, acts of God, the public enemy or
the action of the elements.
2.18.2 Upon termination of this Agreement howsoever caused, County will
require Company to remove from the leased Premises, within thirty
(30) days of termination, all equipment, trade fixtures and personal
property belonging to Company.
For purposes of this Section 2.18.2, the words "equipment, trade
fixtures and personal property" will include, but not be limited to,
signs (electrical or otherwise) used to advertise or identify
Company's business, all equipment used in connection with the conduct
of its business whether or not such equipment is attached to the
Premises; any other mechanical device; and all other miscellaneous
equipment, furnishings and fixtures installed on or placed on or about
the leased Premises and used in connection with Company's business
thereon.
2.18.3 Upon termination of this Agreement, howsoever caused, County will
have option to require either of the following by giving written
notice prior to the date of termination:
2.18.3.1 Company will, commencing within thirty (30) days following
the termination date, remove all or part (as determined by CDR)
of the permanent improvements made to or placed upon the Premises
by Company. Company agrees that it will use due diligence in
completing the removal as may be required herein.
2.18.3.2 Company will leave in place all or part, as determined by
CDR, of the permanent improvements whereupon title and ownership
will pass from Company and vest in County without any further
consideration required from County. Company agrees that it will
immediately provide any transfers of title to County as may be
required.
2.18.3.3 If no written notice is received by Company from County prior
to termination of this Agreement pursuant to this Section 2.18.3,
Section 2.18.3.2 above will apply.
For purposes of this Section 2.18:3, the words "permanent
improvements" means all property of Company upon the Premises which
will include, but not be limited to, paving, buildings, structures and
related appurtenances, wall coverings, carpeting, draperies and light
fixtures.
2.19 FINANCING
2.19.1 Notwithstanding anything to the contrary contained in this
Agreement, Company will have the right at any time during the term
hereof to execute and deliver to any or all of its Lenders any
documents which will operate as collateral security for
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any Loan or Loans made, even if such document or documents result in a
form or type of conveyance or assignment of the leasehold interest
demised hereunder. It is hereby agreed that Company or any such
Lenders) will have the right to immediately record such document or
document(s) with an appropriate public official or officials. Company
agrees that copies of all such documents of conveyance or assignment
as contained in this Section 2.19 will be provided to CDR forthwith.
Any financing arrangement which hypothecates any interest of Company
in or under this Agreement or any conveyance or-assignment to be made
by Company of any interest in or under this Agreement must have the
prior written approval of CDR which consent shall not be unreasonably
withheld or delayed. Notwithstanding the foregoing, Company will have
the right to refinance the outstanding principal balance of any
previously approved Loan with any institutional lender at prevailing
market interest rates without County's consent, provided, in the case
of an existing term loan, such refinancing does not exceed the
remaining original amortization period of the previously approved
Loan. Such approval or consent of the initial or subsequent
assignments to. a Lender or purchaser will be in accordance with
Section 2.1 (entitled ASSIGNMENT) of this Agreement. Any Lender which
will succeed to Company's interest hereunder will so succeed subject
to all the terms and conditions of this Agreement
2.19.2 County will deliver to any such Lender written notice of any default
of Company under the terms of this Agreement and said notice will
specify the nature of the default Before terminating this Agreement,
County will allow such Lender to cure or commence to cure any default
of Company in accordance with Sections 2.15.2 above and this Section
2.19. The time period to cure any default of Company will commence
when said notice is delivered to Lender. Lender and any person
designated by Lender shall have and are hereby granted the right to
enter upon the Premises at any time and from time to time for the
purpose of taking any cure action as described herein. In the event
Company fails to timely cure a default after receipt of written notice
and expiration of any applicable cure period, County agrees to provide
any Lender with a second written notice and provide such Lender with
an additional thirty (30) day cure period. County will not have the
right to exercise any remedies under this Agreement so long as Lender
is diligently prosecuting to complete a cure of any default. If such
default is of a nature which is incapable of being cured by Lender,
County agrees not to exercise its remedies arising from such default
if (a) Lender notifies County in writing within such thirty (30) day
cure period that Lender intends to foreclose its mortgage and Lender
commences and diligently pursues such foreclosure; and (b) Lender
makes all payments due by Company under this Agreement through the
date of foreclosure, to the extent the amount of such payments can be
ascertained by-Len
2.19.3 Any default by Company in the payment of money as required under the
terms of this Agreement may be cured by Lender in accordance with the
terms of Sections 2.15.2 of this Agreement (and subject to the
notification and cure provisions of this Section 2.19), and County
will accept any such payment or cure from such Lender during the term
of Lender's Loan to Company.
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2.19.3.1 Should Company default under the terms of this Agreement and
should the default be such that it cannot be cured by the payment
of money, County will accept payments of rent from such Lender
and this Agreement will not terminate, but will remain in full
force and effect, pending Lender's cure of such default within
the time periods described herein or resort to foreclosure or
sale proceedings under its deed of trust or other security
instruments.
2.19.4 Notwithstanding the provisions of Section 2.19.3:1 above, should
Company default under the terms of this Agreement and should the
default be such that it cannot be cured by the payment of money and
the default (in the sole judgment of County's Designated
Representative) affects the security or safety of the Premises and if
Company's Lender does not wish this Agreement to terminate, then upon
written notice from County such Lender will have the option to cure
immediately or to commence to cure the default in accordance with
Section 2.15.2 of this Agreement. However, if the nature of the
default requires action before the cure time specified in Section
2.15.2 above, the County's Designated Representative may elect to cure
the default County will then present for payment to Company and Lender
a detailed and itemized invoice of County's reasonable expenses
incurred in curing the default.
2.19.5 Subject to the rights of a Lender as otherwise set forth in this
Section 2.19 (including, without limitation, those contained in
Section 2.19.13 below), and notwithstanding any other provisions of
this Agreement, provided that either Company or Lender pays the full
amount of the invoice described in Section 2.19.4 above within thirty
(30) days following receipt, this Agreement will not terminate sooner
than one (1) year from the date of County's notice of default to
Company and Lender, pending such Lender's resort to any foreclosure or
sale proceedings under its deed of trust or other security instrument.
2.19.6 If any default has been cured by a Lender or Assignee, County agrees
that upon completion of any foreclosure proceedings or sale under the
deed of trust or other security securing the Loan, or upon delivery of
a deed in lieu of foreclosure, Lender or Assignee at such sale or any
heir, successor, or Assignee subsequent to such sale will be
recognized by County as the lessee under the terms of this Agreement
for all purposes for the remaining term hereof, subject to County's
approval of such Assignee, to the extent such approval is required in
Section 2.19.11.1 below. The leasehold interest of Lender or such
Assignee will not be adversely affected or terminated by reason of any
non-monetary default occurring prior to the completion of such
proceedings or sale, provided such default has been promptly remedied,
or if such default requires possession to cure, provided such Lender
promptly commences to cure upon taking possession of the Premises.
2.19.7 Such Lender will not become personally liable under the terms and
obligations of this Agreement unless and until it assumes the
obligations and is recognized by County as lessee under this Agreement
and will be liable only so long as such
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Lender maintains ownership of the leasehold interest or estate and
recourse to such Lender shall be limited solely to Lender's interest
in the Premises.
2.19.8 Within thirty (30) days after a written request by Company or any
Lender (but not more than once in any calendar year, except in case of
a proposed financing or refinancing), County, through its Designated
Representative, will execute, acknowledge and deliver to Company or
such person or entity as Company designates, a certificate stating:
a. that this Agreement is the only agreement between County and
Company concerning the teased Premises and is unmodified and in
full force and effect in accordance with the terms (or if there
have been modifications, that this Agreement is in force and
effect as modified, and identifying the modification agreements,
or if this Agreement is not in full force and effect, that it is
not);
b. the commencement and expiration dates of this Agreement and the
date to which rental has been paid to County under this
Agreement;
c. whether or not there is an existing default by Company in the
payment of rental or any other sum of money under this Agreement,
and whether or not there is any other existing default by either
party under this Agreement with respect to which a notice of
default has been served, and if there is such a default
specifying its nature and extent;
d. whether or not there are any set-offs, defenses or counterclaims
against enforcement of the obligations to be performed by County
under this Agreement; and
e. such other information that a Lender or Assignee may reasonably
require.
2.19.9 The bankruptcy or insolvency of Company will not operate or permit
County to terminate this Agreement as long as all rent or other
monetary payments required to be paid by Company continue and other
required obligations are performed in accordance with the terms of
this Agreement. In the event that County or Company terminates this
Agreement, whether as a result of the rejection of this Agreement
pursuant to the federal Bankruptcy Code or otherwise, then, provided
that Lender has cured any monetary defaults under this Agreement, and
provided further that County has not elected to assume any approved
financing, as provided in Section 2.19.11 below, Lender shall have the
right within thirty (30) days after termination of this Agreement to
request and County shall execute a new lease covering the Premises for
the remaining term under same terms and conditions as set forth
herein.
2.19.9.1 The rejection of this Agreement by a trustee-in-bankruptcy of
County shall not affect or impair the lien of any mortgage or
deed of trust in favor of Lender or Lender's rights with respect
to this Agreement. In addition to the leasehold estate created
hereunder in
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favor of Company and all other interest specified in any mortgage
or deed of trust in favor of Lender, the lien of such mortgage or
deed of trust shall attach to, and shall encumber Company's right
to use and possession of the Premises if a trustee-in-bankruptcy
of. County rejects this Agreement This Agreement shall not be
treated as terminated by reason of County's rejection of this
Agreement pursuant to Subsection 365(h)(I) of the federal
Bankruptcy Code without Lender's prior written consent, and any
such purported termination without Lender's prior written consent
shall be null and void and of no force and effect.
2.19.10 To the extent any of the other terms of this Agreement are
inconsistent with the terms of this Section 2.19, this Section 2.19
will control.
2.19.11 Any uncured material default by Company under any approved
financing will be deemed a default under this Agreement. Such default,
however, will be deemed and treated by County as a default not curable
by Lender in accordance with Section 2.19.2 of this Agreement. In the
event of any default by Company under any approved financing, County
reserves the right to assume the financing obligations of Company
under the Loan before Lender resorts to any foreclosure or sale
proceedings under its deed of trust or other security instrument.
2.19.11.1 Following any foreclosure, deed in lieu of foreclosure, or
other transfer in full. or partial satisfaction of Lender's Loan
(a "Foreclosure Transfer"), County shall recognize Lender or any
Lender Affiliate (defined below) designated by Lender as an
Assignee ("Permitted Assignee")_ Such Permitted Assignee shall be
the ground lessee under this Agreement without further consent or
approval by County. In the event of a proposed assignment to an
Assignee other than a Permitted Assignee, whether in connection
with a Foreclosure Transfer or any subsequent assignment of the
leasehold interest evidenced by this Agreement made by Lender or
its Permitted Assignee (who shall have obtained such interest
through a Foreclosure Transfer), County shall have the right to
reasonably approve such Assignee as provided in Section 2.1.1
above. As used in this Section 2.19.11.1, "Lender Affiliate"
means a corporation, limited liability company or other entity
which controls, is owned or controlled by, or is under common
ownership or control with such Lender and such Lender has a net
worth of at least Twenty Million Dollars ($20,000,000).
2.19.11.2 In the event Lender gives County forty-five (45) days notice
of a default by Company under any approved Loan and County
declines the right to assume the financing obligations of Company
under the Loan, the parties agree that Lender or any Lender
Affiliate will be permitted to consider the total unpaid balance
of
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the existing Loan on the date of either (a) Lender's assumption
of the lease or assignment to a Lender Affiliate through
foreclosure sale, or (b) if through a deed or assignment in lieu
of foreclosure, on the date of the recording of such deed, as an
equity contribution to be repaid from all available Net Revenue
with interest at the same rate set forth in Section 1.7.1.2 above
(11% per annum) until such time as the total unpaid balance of
such Loan is fully recovered by such Lender or Lender Affiliate.
Any subsequent third-party Assignee of any such Lender's or
Lender Affiliate's ground leasehold interest in the Premises will
be permitted to consider its initial acquisition price (net of
any debt secured by the ground leasehold interest in the
Premises) as an equity contribution to be repaid from all
available Net Revenue with interest at a rate equal to an
interest rate typical for comparable loans in this market until
such time as such Assignee's total acquisition price is fully
recovered. Notwithstanding the above, if any Lender or Lender
Affiliate or any third-party Assignee makes an equity
contribution to the Project, then such equity contribution will
be entitled to receive the same repayment priority from Net
Revenue with interest at the same rate provided to those equity
contributions described in Section 1.7. 12 above.
2.19.11.3 Subject to County's right to assume the financing
obligations of Company under the Loan, before Lender resorts to
any foreclosure or sale under this Section, in the event of a
default under Lender's mortgage or deed of trust, Lender or
Lender Affiliate shall have the right, after giving notice to
County, to oust Company and take possession of the Premises in
accordance with the terms of Lender's mortgage or deed of trust.
Such ouster shall not constitute a termination of this Agreement,
but shall be deemed an exercise of the assignment of this
Agreement to Lender, which assignment shall not require any
further consent or approval by County.
2.19.11.4 Notwithstanding the above provisions of this Section 2.19.
(entitled FINANCING) to the contrary, the following shall apply:
(1) In the event any Lender forecloses and either a purchaser at
the foreclosure sale or a subsequent assignee of such Lender
acquires the leasehold estate under this Agreement, then, subject
to any right by County to approve such purchaser or Assignee as
provided in this Agreement, such purchaser or Assignee shall pay
the same rental amount that would have been payable by Lender;
(2) any Lender shall have the right to commence, but not complete
foreclosure during the forty-five. (45)-day period available to
County to notify Lender that County shall assume the Loan (as
provided in Section 2.19.11.2 above); and (3) if County assumes
the Loan, County shall not take or permit any action to terminate
this Lease or merge the ground leasehold estate into the fee
estate
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prior to payment of all obligations owing in connection with the
Loan. For purposes of this Section, "ground leasehold estate"
shall mean the leasehold estate granted to Company by County
pursuant to this Agreement
2.19.12 Any mortgage, lien, encumbrance or deed of trust placed by County
on the fee title to the Premises shall be subordinate to this
Agreement (and any replacement to or amendment of this Agreement), any
mortgage or deed of trust encumbering the leasehold estate in favor of
Lender, and all Subleases, whenever arising. County shall obligate the
holder of any such fee mortgage, encumbrance, or deed of trust to
execute and acknowledge any documentation requested by Company or any
Lender to confirm such subordination.
2.19.13 In connection with Lender's cure rights in this Section 2.19, any
Lender shall be allowed sufficient time necessary to complete any
foreclosure action, including delays due to official restraint
(including by law, process or injunction issued by a court), so long
as such Lender is making payments required by this Agreement which can
be reasonably determined prior to acquiring the Company's interest
under this Agreement. Lender shall have the right to terminate
foreclosure proceedings at any time if Company has cured all defaults
under any Loan from Lender.
2.19.14 So long as the mortgage or deed of trust in favor of a Lender is in
effect, there shall be no merger of the leasehold estate created by
this Agreement into the fee simple estate in the Premises without the
prior written consent of such Lender.
2.19.15 Any Lender shall have the right to participate in any settlement or
adjustment of losses under insurance policies maintained by Company
under this Agreement. Such Lender shall be named as a loss payee or
additional insured, as applicable, in accordance with any Loan
documents executed by Company, under the insurance policies required
under this Agreement. In the event any proceeds of such insurance
policies are to be distributed, County and Lender agree to be bound by
the provisions of the Loan documents executed by Company in favor of
Lender and approved by CDR concerning distribution of insurance
proceeds.
2.19.16 Whenever in this Agreement, Company shall have the right to request
any information, statements, documents, or anything else whatsoever
from County, Lender shall have the right to request the same from
County, and such information, statements, documents and other
requested material shall thereafter be given to Lender as if Lender
had requested the same. In addition, County shall furnish Lender with
copies of all notices of default and notices of intent served on
Company under this Agreement concurrently with any delivery to
Company. Such notices shall not be deemed delivered to Company until
they are delivered to Lender.
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2.19.17 In the event Lender succeeds. to title to Company's leasehold
estate through foreclosure or otherwise, all Subleases of the Premises
shall run directly to Lender and all such Sublessees shall attorn and
be permitted to attorn to Lender as the successor sublessor and
perform their obligations to Lender as successor to Company under this
Agreement as if the Sublease were executed directly between Lender and
the Sublessee. Provided County has elected not to assume the financing
obligations of Company under the Loan as provided in Section 2.19.11
of this Agreement, County hereby agrees to subordinate County's own
attornment rights with respect to any such Sublessee contained in this
Agreement to the attornment rights of Lender.
2.19.18 County agrees to notify Lender and Company of any assignment,
transfer, conveyance or sale of County's interest in this Agreement
and/or the fee interest in the Premises and will furnish Lender and
Company with the name and address of such assignee, transferee,
grantee or buyer.
2.19.19 Lender shall have the right to participate in any arbitration
proceedings in connection with any matter under this Agreement
materially affecting Lender's interest. Notwithstanding the foregoing,
Lender shall not have the right to participate in any arbitration
related to a proposed annual operating budget (as provided in Section
1.6 above).
2.20 RECOVERY OF PREMISES
2.20.1 County may, in its unlimited discretion, at any time during the term
of this Agreement or any extensions thereof, recover all or any part
of the Premises for other Airport or public uses (except for
commercial facilities purposes). Prior to the exercise of this power
of recovery, County agrees to give Company one (I) year's prior
written notice of its intention to exercise this power.
2.20.1.1 In the event of such recovery of the Premises by County (or
other condemnation or recovery of all or substantially all of the
Premises) during the first thirty (30) years of this Agreement,
County will pay to Company an amount equal to the greater of
either (i) all amounts outstanding under any Loan or under Loan
documents approved by County pursuant to Section 2.19 above,- or
(ii) the sum of all unreimbursed equity contribution and related
interest due to Company plus fifty percent (50%) of the value of
the improvements (excluding land, Company unreimbursed equity,
the existing approved Loan balance, if any, and any amounts paid
by County pursuant to Section. 2.20.1.1.1 below) as determined by
a competent real estate appraiser acceptable to Company and CDR.
2.20.1.1.1 Upon notice from Company, or, in the event of a total
recovery, upon notice from Company's Lender, County will pay
to Company's Lender all sums due to Lender under the
approved Loan documents evidencing and
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securing the Loan secured by the improvements on the
Premises. Notwithstanding and in replacement of the
foregoing, if Lender or approved Assignee of Lender has
succeeded to the interest of Company, and the outstanding
Loan has been repaid, County shall pay Lender the amount
which was due Lender on the date of foreclosure or transfer
of title (or to such approved Assignee the amount Assignee
paid Lender to assume this Agreement), and an amount equal
to any costs incurred by Lender or such Assignee to cure
Company's defaults under this Agreement or to otherwise
comply with Company's obligations under this Agreement, less
any amount of equity contributions or accrued interest (in
accordance with Section 2.19.11.2 above) that has previously
been repaid from Total Revenue.
2.20.1.2 In the event of such recovery of the Premises by County (or
any other condemnation or recovery of all or substantially all of
the Premises) during the last twenty (20) years of this
Agreement, County will pay to Company fifty percent (50%) of the
residual leasehold value of the improvements on the Premises
based on the remaining term of this Agreement, minus any
outstanding Loan balance. Such leasehold value shall exclude the
value of the land after deducting any amounts paid by County
pursuant to Section 2.20.1.2.1 below. The residual leasehold
value will be as determined by. a competent real estate
appraiser acceptable to Company and CDR.
2.20.1.2.1 Upon notice from Company or, in the event of a total
recovery, upon notice from Company's Lender, County will pay
to Company's Lender all sums due to Lender under the
approved Loan documents evidencing and securing the Loan,
and any subsequent financing that has been approved by CDR
secured by the improvements on the Premises. Notwithstanding
the foregoing, if Lender or approved Assignee of Lender has
succeeded to the interest of Company, and the outstanding
Loan has been repaid, County shall pay Lender the amount
which was due Lender on the date of foreclosure or transfer
of title (or to such approved Assignee the amount Assignee
paid Lender to assume this Agreement), and an amount equal
to any costs incurred by Lender or such Assignee to cure
Company's defaults under this Agreement or to otherwise
comply with Company's obligations under this Agreement, less
any amount or equity contributions or accrued interest (in
accordance with Section 2.19.11.2 above) that has previously
been repaid from Total Revenue to Lender or its assigns.
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2.20.1.3 County will have no obligation for any encumbrance of the
improvements, which has not received County written approval' as
defined in Section 2.19 (entitled FINANCING) above.
2.20.1.4 In the event of any partial condemnation or recovery by any
agency other than County, or in the event of any such
condemnation or recovery, Company will be entitled to file an
action to receive condemnation proceeds for recovery of its
leasehold improvements and its leasehold interest.
2.20.1.5 In the event of a partial condemnation or recovery by another
agency, this Agreement shall remain in full force and effect as
to the portion of the Premises remaining.
On a partial recovery, all sums, including damages and
interest, awarded for the fee or the leasehold or both shall
(i) be delivered to County and Company (or to any Lender),
respectively, if such award has been apportioned between
County and Company by such condemning authority, or (ii) be
deposited promptly with an escrow agent selected by Company
in the reasonable exercise of its discretion if there is
only a single award, to be distributed and disbursed as
follows:
a. First, to taxes constituting a superior lien on the
portion of the Premises taken;
b. Second, to County an amount equal to the then present
value of County's interest in the income stream from
rental payments attributable to the portion of the
Premises being taken, measured by the diminution in
rental payments, plus an amount equal to the then
present value of the reversionary interest of County at
the expiration of this Agreement in that portion of the
real property underlying the Premises that is taken in
such partial recovery; and
c. Third, subject to the rights of any Lender of record,
the balance of the award to Company.
Sums being held by an approved escrow agent pending
disbursement shall be deposited in one or more federally
insured interest-bearing account(s) and, upon disbursement,
each party having aright to any of the sums being disbursed
shall be entitled to receive the interest attributable to
its share of said sums.
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2.20.1.6 Notwithstanding any language to the contrary in this Section
2.20, in the event of partial taking of the Premises by
condemnation, if, in the opinion of County, Company, and Lender,
the remainder of the Premises are suitable for continued
operation, this Lease shall not terminate in regard to the
portion not taken. In the event of a partial or total taking of
the Premises by condemnation, County and Company agree (a) to be
bound by the provisions of the Loan documents executed by Company
in favor of Lender concerning condemnation process and proceeds,
including the right of Lender to recover from such condemnation
proceeds an amount up to the then unpaid balance of its Loan, and
(b) that Lender shall have the right to participate in any
condemnation proceedings as set forth in this Section 2.20 or as
otherwise provided by law.
ARTICLE III
3.1 MAINTENANCE AND OPERATION NONDISCRIMINATION COMPLIANCE
Company, for itself, its heirs, personal representatives, successors in
interest, and assigns, as a part of the consideration hereof, does hereby
covenant and agree as a covenant running with the land that in the event
facilities are constructed, maintained, or otherwise operated on the said
property described in this Agreement for a purpose for which a U.S.
Department of Transportation program or activity is extended or for_
another purpose involving the provision of similar services or benefits,
Company will maintain and operate such facilities and services in
compliance with all other requirements imposed pursuant to 49 CFR Part 21,
Nondiscrimination in Federally Assisted Programs of the Department of
Transportation and as said Regulation may be amended.
3.2 NONDISCRIMINATION IN PARTICIPATION, CONSTRUCTION AND USE OF PREMISES
Company, for itself, its personal representatives, successors in interest
and assigns and as a part of the consideration hereof, does hereby covenant
and agree as a covenant running with the land that:
3.2.1 No person on the grounds of race, color, or national origin will be
excluded from participation in, denied the. benefits of, or be
otherwise subjected to discrimination in the use of said facilities.
3.2.2 That in the construction of any improvements on, over, or under such
land and the furnishing of services thereon, no person on the grounds
of race, color or national origin will be excluded from participation
in, denied the benefits of, or otherwise be subject to discrimination.
3.2.3 That Company will use the Premises in compliance with all other
requirements imposed by or pursuant to 49 CFR. Part 21,
Nondiscrimination in Federally Assisted Programs of the Department of
Transportation and as said Regulations may be amended.
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3.3 TERMINATION RIGHTS FOR BREACH OF SECTIONS 3.1 AND 3.2 ABOVE
In the event of breach of any of the nondiscrimination covenants described
in Sections 3.1 and 3.2 above, County will have the right to terminate this
Agreement and to reenter and repossess this land and the facilities
thereon, and hold the same as if this Agreement had never been made or
issued. This provision, however, does not become effective until the
procedures of 49 CFR Part 21 are followed and completed including
expiration of appeal rights. Promptly upon the receipt of any complaint or
other notice alleging violation of the covenants in Sections 3.1 and 3.2
above, County will notify Company and will provide Company the opportunity
to defend the same. Unless disapproved by the U.S. Department of
Transportation, any such termination and reentry rights shall not be
exercised by County so long as the current Lender elects to exercise its
rights and remedies and acquire Company's interest under this Agreement
Such Lender will not be required to cure any breach by Company of any
covenants in Sections 3.1 through 3.5 of this Agreement, provided, however,
such Lender shall be obligated to comply with such Sections upon any
acquisition of Company's interest under this Agreement.
3.4 NONDISCRIMINATION IN FURNISHING ACCOMMODATIONS AND/OR SERVICES
Company will furnish its accommodations and/or services on a fair, equal
and not unjustly discriminatory basis to all users thereof and it will
charge fair, reasonable and not unjustly discriminatory prices for each
unit or service; provided that Company may be allowed to make reasonable
and nondiscriminatory discounts, rebates or other similar type of price
reductions to volume purchasers.
3.5 RIGHTS FOR NONCOMPLIANCE WITH SECTION 3.4
Noncompliance with Section 3.4 above will constitute a material breach of
this Agreement and in the event of such noncompliance, County will have the
right to terminate this Agreement and the estate hereby created without
liability therefor or at the election of County or the United States of
America either or both said Governments will have the right to judicially
enforce the provision. Unless disapproved by the U.S. Department of
Transportation, any such termination and reentry rights shall not be
exercised by County so long as the current Lender elects to exercise its
rights and remedies and acquire the Company's interest under this
Agreement. Such Lender will not be required to cure any breach by Company
of any covenants in Section 3.4 above, provided, however, such Lender shall
be obligated to comply with such Sections upon any acquisition of Company's
interest under this Agreement.
3.6 COMPANY'S OBLIGATION 49 CFR PART 26, SUBPART F
3.6.1 This Agreement is subject to the requirements of the U.S. Department
of Transportation's regulations, 49 C H Part 26, Subpart F. Company
agrees that it will not discriminate against any business owner
because of the owner's race, color, national origin or sex in
connection with the award or performance of any agreement covered by
49 CFR Part 26, Subpart F.
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3.6.2 Company agrees to include the language in Sections 3.1 through 3.6.1
above in any subsequent Sublease, professional services and/or
construction agreements that it enters and cause those businesses to
similarly include the statements in further agreements; provided
however, that the foregoing is neither intended to nor shall require
any Sublessee to include any such provisions in any contracts or
agreements relative to the operations of its business. Such inclusion
may be made by way of reference to such sections (as opposed to
restatement of such sections in any such agreement).
3.7 SUBAGREEMENT NONDISCRIMINATION COMPLIANCE
Company hereby assures it will include Sections 3.1 through 3.6.1 above in
all Subleases and cause Sublessees to similarly include such sections in
further Subleases; provided however, that the foregoing is neither intended
to nor shall require any Sublessee to include any such provisions in any
contracts or agreements relative to the operations of its business. Such
inclusion may be made by way of reference to such sections (as opposed to
restatement of such sections in any such Sublease).
3.8 COMPANY OBLIGATION
Company hereby assures that no person shall be excluded from participation
in, denied the benefits of or otherwise be discriminated against in
connection with the award and performance of any contract, including
leases, covered by 49 CFR Part 26 on the grounds of race, color, national
origin or sex.
3.9 APPENDIX 9, GENERAL CIVIL RIGHTS PROVISION
Company assures that it will comply with pertinent statutes, Executive
Orders and such rules as are promulgated to assure that no person shall, on
the grounds of race, creed, color, national origin, sex, age or handicap be
excluded from participating in any activity conducted with or benefiting
from Federal assistance. This provision obligates Company or its transferee
for the period during which Federal assistance is extended to the Airport
program, except where Federal assistance is to provide, or is in the form
of, personal property or real property or interest therein or structures or
improvements thereon. In these cases, this provision obligates the party or
any transferee for the longer of the following periods: (a) the period
during which the property is used by the sponsor or any transferee for a
purpose for which Federal assistance is extended, or for another purpose
involving the provision of similar services or benefits; or (b) the period
during which the Airport sponsor or any transferee retains ownership or
possession of the property. In the case of contractors, this provision
binds the contractors from the bid solicitation period through the
completion of the contract Compliance with the Americans With Disabilities
Act, 42 U.S.C. Section 12101, et seq., as amended, by Company, shall be
considered compliance with Company's duty to assure that no person shall,
on the grounds of handicap be excluded from participating in any activity
conducted with or benefiting from Federal assistance.
3.10 AFFIRMATIVE ACTION EMPLOYMENT PROGRAMS
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3.10.1 Company assures that it will undertake an Affirmative Action Program
as required by 14 C.1-R. Part 152, Subpart E, to ensure that no person
shall on the grounds of race, creed, color, national origin, or sex,
be excluded from participating in any employment activities covered in
14 CFR Part 152, Subpart E. Company assures that no person will be
excluded on these grounds from participating in or receiving the
services or benefits of any program or activity covered by this
subpart. Company assures that it will require that its covered
sub-organizations provide assurances to Company that they similarly
will undertake Affirmative Action Programs and that they will require
assurances from their sub-organizations, as required by 14 CFR Part
152, Subpart E to the same effect.
3.10.2 Company agrees to comply with any affirmative action plan or steps
for equal employment opportunity required by 14 CFR Part 152, Subpart
E, as part of the Affirmative Action Program, and by any Federal,
State, or local agency or court, including those resulting from a
conciliation agreement, a consent decree, court order or similar
mechanism. Company agrees that State or local affirmative action plans
will be used in lieu of any affirmative action plan or steps required
by 14 CFR Part 152, Subpart E, only when they fully meet the standards
set forth in 14 CFR, Subpart 152.409. Company agrees to obtain a
similar assurance from its covered organizations, and to cause them
to require a similar assurance of their covered sub-organizations, as
required by 14 CFR Part 152, Subpart E.
3.10.3 In the event Company employs fifty (50) or more employees on the
Airport, it agrees to prepare and keep on file for review by the FAA
Office of Civil Rights, an affirmative action plan developed in
accordance with standards in 14 CFR, Subpart 152.409. Such program
will be updated on an annual basis. Should Company employ less than
fifty (50) employees on the Airport, it will annually send written
correspondence confirming the exemption.
3.10.4 This Section 3.10 is not intended to apply to any Sublessee of
Company.
3.11 AIRPORT MAINTENANCE, REPAIR, DEVELOPMENT AND EXPANSION
County reserves the right to further develop or improve the landing area or
any other area, building or other improvement within the present or future
boundaries of the Airport as it sees fit in its sole judgment regardless of
the desires or view of Company and without interference or hindrance by
Company. Further, County retains the absolute right to maintain, repair,
develop and expand the terminal building, any other Airport facility,
Airport improvement or Airport property free from any and all liability to
Company for loss of business or damage of any nature whatsoever as may be
occasioned during or because of the performance of such maintenance,
repair, development or expansion.
3.12 MAINTENANCE, REPAIR, DIRECTION AND CONTROL
County reserves the right, but is not obligated to exercise the right, to
maintain and keep in repair the landing area of the Airport and all
publicly owned facilities of the Airport, together with the right to direct
and control all activities of Company in this regard. These
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areas will include, but are not limited to, those areas which are not
necessary to serve the aeronautical users of the Airport, except that
County will not be obligated to maintain and keep in repair such areas of
the Airport as may be leased to or under the control of Airport tenants
whether such area serves aeronautical users or otherwise.
3.13 AGREEMENTS WITH THE UNITED STATES OF AMERICA
This Agreement will be subject and subordinate to the provisions and
requirements of any existing or future agreement between County and the
United States of America relative to the development, operation or
maintenance of the Airport. Notwithstanding the foregoing, County agrees
that no existing agreements between County and the United States of America
relating to the same (i) currently prohibit or materially affect the use
and/or operation of the Premises as contemplated under this Agreement, or
(ii) defeat the lien of the mortgage or deed of trust in favor of a Lender
and/or the leasehold estate in favor of Company created by this Agreement.
Should any future agreements between County and the United States of
America materially impair the use of the Premises or Lender's interest
therein, such agreements shall be considered an action to recover the
Premises under Section 220 above.
3.14 OPERATION OF AIRPORT BY THE UNITED STATES OF AMERICA
This Agreement and all the provisions hereof will be subject to whatever
right the United States of America now has or in the future may have or
acquire, affecting the control, operation, regulation and taking over of
the Airport or the exclusive or nonexclusive use of the Airport by the
United States during the time of war or national emergency.
3.15 PART 77 OF FEDERAL AVIATION REGULATIONS
Company agrees to comply with the notification and review requirements
covered in Part 77 of the Federal Aviation Regulations in the event future
construction of a building is planned for the Premises, or in the event of
any planned modification or alteration of any present or future building or
structure situated on the Premises.
3.16 NONEXCLUSIVE
It is understood and agreed that nothing herein contained will be construed
to grant or authorize the granting of an exclusive right within the meaning
of 49 U.S.C. Section 40103(e) (formerly known as Section 308 of the Federal
Aviation Act of 1958 (49 U.S. C. Section 1349a)).
3.17 AIRSPACE
There is hereby reserved to County, its successors and assigns, for the use
and benefit of the public, a right of flight for the passage of Aircraft in
the airspace above the surface of the Premises herein leased. This public
right of flight will include the right to cause or allow in said airspace,
any noise inherent in the operation of any Aircraft used for navigation or
flight through the said airspace or landing at, taking off from or
operation
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on the Airport. No liability on the part of County will result from the
exercise of this right.
3.18 AIRPORT OBSTRUCTIONS
Company by accepting this Agreement expressly agrees for itself, its
successors and assigns, that it will not erect nor permit the erection of
any structure or object nor permit the growth of any tree on the land
leased hereunder which will exceed such maximum height as may be stipulated
by County. It is understood and agreed that applicable laws, codes,
regulations or agreements concerning height restrictions will govern the
maximum height to be stipulated by County. In the event the aforesaid
covenants are breached, County reserves the right to enter upon the land
leased hereunder and to remove the offending structure or object and cut
down the offending tree all of which will be at the expense of Company and
without liability to County.
3.19 AIRPORT HAZARDS
Company by accepting this Agreement agrees for. itself, its successors and
assigns, that it will not make use of the Premises in any manner which
might interfere with the landing and taking off of Aircraft from the
Airport or otherwise constitute a hazard or obstruction. In the event the
aforesaid covenant is breached, County reserves the right to enter upon the
Premises hereby leased and cause the abatement of such interference at the
expense of Company and without liability of any kind.
3.20 AIRPORT RULES AND REGULATIONS AND AIRPORT OPERATING DIRECTIVES
County, through its Designated Representative, will have the right to
adopt, amend and enforce reasonable rules and regulations and operating
directives with respect to use of and the conduct and operation of the
Airport, its terminal buildings or any improvements within the present or
future boundaries of the Airport which Company agrees to observe and obey.
3.21 COMPLIANCE WITH PUBLIC AUTHORITIES
3.21.1 Company will not use or permit the use of the demised Premises or
any other portion of the Airport for any purpose or use other than
authorized by this Agreement or as may be authorized by other,
separate; written agreement with County.
3.21.2 Company, its employees, representatives or agents will comply with
all present or future laws, rules and regulations and amendments or
supplements thereto governing or related to the use of the Airport or
the demised Premises as may from time to time be promulgated by
Federal, State or local governments and their authorized agencies.
3.22 ENVIRONMENTAL POLICY
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3.22.1 Violation Of Environmental Laws
Company will not cause or permit any hazardous material to be used,
generated, manufactured, produced, stored; brought upon, transported
to or from, or otherwise released on, under or about the Premises or
transported to and from the Premises by Company, its Sublessees, their
agents, employees, contractors, invitees, or a third party in
violation of the Environmental Laws as defined in Section 1.1
(entitled DEFINITIONS) above.
3.22.1.1 CDR will have access to the Premises to inspect same to
insure that Company is using the Premises in accordance with
environmental requirements.
3.22.1.2 3Company, at CDR's reasonable request, at Company's expense,
will conduct such testing and analysis as necessary to ascertain
whether Company is using the Premises in compliance with
environmental requirements_ Any such tests will be conducted by
qualified independent experts chosen by Company and subject to
CDR's reasonable written approval. Copies of such reports from
any such testing will be provided to CDR.
3.22.1.3 Company will provide copies of all notices, reports, claims,
demands or actions concerning any' environmental concern or
release or threatened release of hazardous materials or special
wastes to the environment.
3.22.2 Contamination Of Premises
If the presence of any Hazardous Material on, under or about - the
Premises caused or permitted by Company results in any contamination
of the Premises, in violation of an Environmental Law, Company will
promptly take all actions, at its sole cost and expense, as are
necessary to return the Premises to the condition existing prior to
the introduction of any such Hazardous Material to the Premises.
Company will take all steps necessary to remedy and remove any such
hazardous materials and special wastes and any other environmental
contamination as is presently or subsequently discovered on or under
the Premises as are necessary to protect the public health and safety
and the environment from actual or potential harm and to bring the
Premises into compliance with all environmental requirements;
provided, however, County will be solely responsible for any
environmental condition existing on or about the Premises prior to the
Approval Date or any environmental conditions caused by County during
the term or arising in any way and at any time from the Airport, Such
procedures are subject to:
3.22.2.1 Prior written approval of CDR, which approval will not be
unreasonably withheld. Company will submit to CDR a written plan
for completing all remediation work. CDR retains the right to
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review and inspect all such work at any time using consultants
and/or representatives of his/her choice.
3.22.2.2 Such actions of remediation by Company will not potentially
have any material adverse long-term effect on the Premises in the
reasonable judgment of CDR.
3.22.3 Compliance With All Governmental Authorities
Company will promptly make all submission to, provide all information
to, and comply with all requirements of the appropriate governmental
authority under. all Environmental Laws as defined in Section 1.1
(entitled DEFINITIONS) of this Agreement.
3.22.3.1 Should the Government determine that a site characterization,
site assessment, and/or cleanup plan be prepared or that a
cleanup should be undertaken because of any spills or discharges
of hazardous materials at the Premises which occur during the
term of this Agreement then. Company shall prepare and submit
required plans and financial assurances, and carry out the
approved plans. Company will promptly provide all information
requested by CDR to determine the applicability of the
Environmental Laws to the Premises, or to respond to any
governmental investigation or to respond to any claim of
liability by third parties which is related to environmental
contamination.
3.22.3.2 Company's obligations and liabilities under this provision
will continue so long as County bears any responsibility under
the Environmental Laws for any action that occurred on the
Premises during the term of this Agreement.
3.22.3.3 This indemnification of County by Company includes, without
limitation, costs incurred in connection with any investigation
of site conditions or any cleanup, remedial, removal,
restoration, any fines or penalties issued to Company, or any
other work required by any Federal, State or local governmental
agency or political subdivision because of hazardous material
located on the Premises or present in the soil or ground water
on, under or about the Premises.
3.22.3.4 The parties agree that County's right to enforce Company's
promise to indemnify is not an adequate remedy at law for
Company's violation of any provision of this Agreement. County
will also have the rights set forth in Section 3.22.4 (entitled
County's Termination Rights for Violation of Environmental Laws),
or Section 2.15 (entitled TERMINATION BY COUNTY)
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of this Agreement, in addition to all other rights and remedies
provided by law or otherwise provided in this Agreement.
3.22.4 County's Termination Rights for Violation of Environmental Laws
3.22.4.1 Company's failure or its Sublessees, their agents, employees,
contractors, invitees, or the failure of a third party to comply
with any of the remediation requirements of this Agreement or
applicable Environmental Laws will constitute a material default
under this Agreement and will permit County to pursue the
following remedies, in addition to all other rights and remedies
provided by law or otherwise provided in this Agreement, to which
County may resort cumulatively, or singularly, in the
alternative:
3.22.4.1.1 County may, at County's election, keep this Agreement in
effect and enforce all of its rights and remedies under this
Agreement, including (i) the right to recover rent and other sums
as they become due by the appropriate legal action and/or (ii)
the right, upon ten (10) days' written notice to Company, to make
payments required of Company or perform Company's obligations
and, be reimbursed by Company for the cost thereof, unless such
payment is made or obligation performed by Company within such
ten (10) day period.
3.22.4.1.2 County may, at County's election, subject to Lender's right
to cure as provided in Section 2.19 (entitled FINANCING) above,
terminate this Agreement upon written notice to Company as
provided in Section 2.15 (entitled TERMINATION BY COUNTY) above.
If this Agreement is terminated under this provision, Company
waives all rights against County, including, but not limited to,
breach of contract, costs of design, installation or construction
of improvements and/or interruption of business.
3.22.4.1.3 Notwithstanding any other provision in this Agreement to
the contrary, County' will have the right of "self-help" or
similar remedy in order to minimize any damages, expenses,
penalties and related fees or costs, arising from or related to a
violation of Environmental Law on, under or' about the Premises.
3.23 AMERICANS. WITH DISABILITIES ACT
Company will throughout the term of this Agreement be in compliance with
all applicable provisions of the Americans With Disabilities Act, 42 U.S.C.
Section 12101, et seq.
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ARTICLE IV
4.1 FORCE MAJEURE
Neither County nor Company will be deemed to be in breach of this Agreement
by reason of failure to perform any of its obligations hereunder if, while
and to the extent that such failure is due to strikes, boycotts,
labor-disputes, embargoes, shortages of materials, acts of God, acts of the
public enemy, acts of governmental authority, unusual weather conditions,
floods, riots, rebellion or sabotage. However, the provisions of this
Section will not apply to failure by Company to pay rents, fees or any
other money payments required under other provisions, covenants or
agreements contained in this Agreement.
4.2 QUIET ENJOYMENT
County agrees that, on payment of the rentals and fees and performance of
the covenants, conditions and agreements on the part of Company to be
performed hereunder, Company will have the right to peaceably occupy and
enjoy the Premises.
4.3 NONLIABILITY OF INDIVIDUALS
No officer, member, manager, agent or employee of either party to this
Agreement will be charged personally or held contractually liable by or to
the other party under any term or provision of this Agreement or because of
any breach thereof, or because of its or their execution or attempted
execution.
4.4 NOTICES
Any notice or communication to be given under the terms of this Agreement
("Notice") shall be in writing and shall be personally delivered or sent by
facsimile, overnight delivery, by nationally-recognized courier, or
registered or certified mail, return receipt requested.
Notices shall be addressed as follows:
If to County: Clark County, Nevada
Department of Real Property Management
Airport Lands Unit
500 South Grand Central Parkway, 4th Floor
P.O. Box 551825
Las Vegas, Nevada 89155-1825
FAX: (702) 261-5050
If to Company: Beltway Business Park Warehouse No. 2, LLC
c/o Majestic Realty Co.
4155 W. Russell Road, Suite C
Las Vegas, Nevada 89118
Attn: Rodman C. Martin
|
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FAX: (702) 896-4838
with a copy to:
Beltway Business Park Office Warehouse No. 2, LLC
c/o Majestic Realty Co.
13191 Crossroads Parkway North, Sixth Floor
City of Industry, California 91746
Attn: Edward P. Rosh, Jr.
FAX: (562) 692-1553
and
Beltway Business Park Warehouse No. 2, LLC
c/o Thomas & Mack Co.
2300 W. Sahara Ave., Suite 530
Las Vegas, Nevada 89102
Attn: Thomas A. Thomas
FAX: (702) 920-2826
4.5 HEADINGS, TITLES OR CAPTIONS
Article, section or paragraph headings, titles or captions are inserted
only as a matter of convenience, and for reference, and in no way define,
limit or describe the scope or extent of any provision of this Agreement.
4.6 INVALID PROVISIONS
It is expressly understood and agreed by and between the parties hereto
that in the event any covenant, condition or provision herein contained is
held to be invalid by any court of competent jurisdiction, the invalidity
of such covenant, condition or provision will in no way affect any other
covenant, condition or provision herein contained; provided, however, that
the invalidity of any such covenant, condition or provision does not
materially prejudice either County or Company in their respective rights
and obligations contained in the valid covenants, conditions or provisions
of this Agreement.
Should any portion of this Agreement be determined by any court of
competent jurisdiction to be in violation of the SNPLMA it is expressly
agreed that Company and County will negotiate in good faith to modify such
terms or portions of this Agreement in order to comply with such Act.
County and Company agree that they will negotiate in good faith to resolve
any issue regarding compliance with the Act for a period of one hundred
eighty (180) days. If the parties cannot agree on a resolution during such
period, either party may terminate this Agreement with ninety (90) days
written notice to the other party. Notwithstanding the above to the
contrary, no such termination shall be effective without the prior written
consent of all current Lenders.
4.7 STATE OF NEVADA LAW
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This Agreement will be interpreted under and governed by the laws of the
State of Nevada.
4.8 CONSENT TO AMENDMENTS
In the event that the FAA or its successors require modifications or
changes in this Agreement as a condition precedent to the granting of funds
for the improvement of the Airport, or otherwise, Company agrees to consent
to such amendments, modifications, revisions, supplements, or deletions-of
any of the terms, conditions, or requirements of this Agreement as may be
reasonably required. Any expenses resulting from such amendments,
modifications, revisions, supplements or deletions, shall be born solely by
Company.
4.9 ADVERSE TENANCY
Any unauthorized holding over by Company for more than one hundred eighty
(180) days after the termination of this Agreement or the expiration of its
terms without the written consent of County, except for the period
authorized for removal of Company's property upon the expiration or
termination hereof, shall entitle County to collect from Company as
liquidated damages for such holding over, one hundred twenty five percent
(125%) of the then rent. County may perfect a lien on the property of
Company as security for the payment of any damages or unpaid rentals, fees,
and/or revenues and shall be entitled to collect the same by foreclosure of
such lien and sale of such property. Any such lien shall be subordinate to
the lien of a Lender. Nothing herein shall limit County's rights to seek
immediate eviction.
4.10 DISPUTES
Any and all disputes arising under this Agreement, which cannot be
administratively resolved, shall be determined according to the laws of the
State of Nevada, and Company agrees that the venue of any such dispute,
shall be in Clark County, Nevada. Company agrees as a condition of this
Agreement that notwithstanding the existence of any dispute between the
parties, insofar as is possible under the terms of this Agreement, each
party shall continue to perform the obligations required of it during the
continuation of any such dispute, unless enjoined or prohibited by a court
of competent jurisdiction.
4.11 AGENT FOR SERVICE OF PROCESS
The parties hereto expressly understand and agree that if Company is not a
resident of the State of Nevada, or is an association or partnership
without a member or partner resident of said State, or is a foreign
corporation, and then in any such event Company does designate its State of
Nevada registered agent as its agent for the purpose of service of process
in any court action between it and County arising out of or based upon this
Agreement, and the service shall be made as provided by the laws of the
State of Nevada by serving also Company's registered agent. The parties
hereto expressly agree, covenant, and stipulate that Company shall also
personally be served with such process out of this State by the registered
mailing of such complaint and process to Company at the address set forth
herein. Any such service out of this State shall constitute valid
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service upon Company as of the date of receipt thereof. The parties hereto
further expressly agree that Company is amenable to and hereby agrees to
the process so served, submits to the jurisdiction, waives any and all
obligations and protests thereto, any laws to the contrary notwithstanding.
4.12 GENDER
Words of any gender used in this Agreement shall be held and construed to
include any other gender, and words in the singular number shall be held to
include the plural, unless the context otherwise requires.
4.13 ENTIRE AGREEMENT
4.13.1 This document represents the entire agreement between the parties
hereto and will not be modified or canceled by mutual agreement or in
any manner except by instrument in writing, executed by the parties or
their respective successors in interest, and supersedes all prior oral
or written agreements and understandings with respect to the subject
matter hereof. The parties further understand and agree that the-
other party and its agents have made no representations or promises
with respect to this Agreement or the making or entry into this
Agreement, except as in this Agreement expressly set forth, and that
no claim or liability for cause for termination shall be asserted by
either party. against the other, and such party shall not be liable by
reason of, the making of any representations or promises not expressly
stated in this Agreement, any other written or oral agreement with the
other party being expressly waived.
4.13.2 The individuals executing this Agreement personally warrant that
they have full authority to execute this Agreement on behalf of the
entity for whom they are acting herein.
4.13.3 The parties hereto acknowledge that they have thoroughly read this
Agreement, including any exhibits or attachments hereto, and have
sought and received whatever competent advice and counsel was
necessary for them to form a full and complete understanding of all
rights and obligations herein.
4.14 SUCCESSORS AND ASSIGNS
This Agreement shall be binding upon and shall inure to the benefit of the
parties hereto and their respective heirs, personal representatives,
successors, or assigns, as the case may be.
4.15 COUNTERPARTS
This Agreement may be executed in any number of counterparts, each of which
when so executed shall constitute in the aggregate but one and the same
document.
4.16 SUSPENSION AND ABATEMENT
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In the event that County's operation of the Airport or Company's operation
from the Premises should be restricted substantially by action of the
federal government or agency thereof or by any judicial or legislative
body, then either party hereto will have the right, upon written notice to
the other, to a suspension of this Agreement and an abatement of an
equitable proportion of the payments to become. due hereunder, from the
time of such notice until such restrictions will have been remedied and
normal operations restored.
4.17 INDEPENDENT CONTRACTOR
Company is deemed to be an independent contractor for all purposes
regarding its operations at the Premises, and no agency, express or
implied, exists.
4.18 FURTHER ASSURANCES
Each party to this Agreement shall perform any and all acts and execute and
deliver any and all documents as may be necessary and proper under the
circumstances in order to accomplish the intents and purposes of this
Agreement and to carry out its provisions.
(Intentionally left blank -- signature page to follow)
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IN WITNESS WHEREOF, County and Company have executed these presents as of
the day and year first above written.
ATTEST: COUNTY:
COUNTY CLERK COUNTY OF CLARK, a political subdivision
of the State of Nevada
By: By: /s/ Sandra M. Norskog
--------------------------------- ------------------------------------
Its: Deputy Clerk Name: Sandra M. Norskog
Its: Director of Real Property Mgt.
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APPROVED AS TO FORM:
David Rogers, District Attorney
COMPANY:
By: /s/ Holly Gordon BELTWAY BUSINESS PARK WAREHOUSE
--------------------------------- NO. 2, LLC, a Nevada limited liability
Holly Gordon company
Deputy District Attorney
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By: MAJESTIC BELTWAY WAREHOUSE
BUILDINGS, LLC, a Delaware limited
liability company, its Manager
By: MAJESTIC REALTY CO.,
a California corporation,
Manager's Agent
By: /s/ Edward P. Roski, JR.
------------------------------------
Name: Edward P. Roski, JR.
Its: Chairman and Chief Executive
Officer
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By:
Name:
Its:
By: THOMAS & MACK BELTWAY, L.L.C.,
a Nevada limited liability company,
its Manager
By: /s/ Thomas A. Thomas
------------------------------------
Name: Thomas A. Thomas
Its: Manager
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EXHIBIT J
TENANT'S LIMITED RESTORATION OBLIGATION
All buildings and other above-ground improvements located on the
Additional Land, but excluding perimeter walls (other than those which front a
public roadway, which must be removed by Tenant if so requested in writing by
Landlord), underground utility lines and facilities, paving, curbs, gutters, and
other roadway and driveway improvements, sidewalks, landscaping, surface water
drainage facilities, parking bumpers, and other similar improvements.
7155 Lindell Road
Las Vegas, Nevada
Nevada Power Company
J-1
Exhibit 10(B)
FINANCING AGREEMENT
Dated as of November 1, 2006
By and Between
HUMBOLDT COUNTY, NEVADA
and
SIERRA PACIFIC POWER COMPANY
RELATING TO
POLLUTION CONTROL REFUNDING REVENUE BONDS
(SIERRA PACIFIC POWER COMPANY PROJECT)
SERIES 2006
The amounts payable to the Issuer (except for amounts payable to, and
certain rights and privileges of, the Issuer under Sections 4.2(e), 4.2(g), 5.3
and 6.4 hereof and any rights of the Issuer to receive any notices,
certificates, requests, requisitions or communications hereunder) and certain
other rights of the Issuer under this Financing Agreement have been pledged and
assigned under the Indenture of Trust dated as of November 1, 2006, between the
Issuer and The Bank of New York, as Trustee.
FINANCING AGREEMENT
TABLE OF CONTENTS
(This Table of Contents is not a part of this Agreement
and is only for convenience of reference).
SECTION HEADING PAGE
------- ------- ----
ARTICLE I DEFINITIONS............................................. 1
ARTICLE II REPRESENTATIONS......................................... 5
Section 2.1. Representations and Covenants by the Issuer............. 5
Section 2.2. Representations by the Company.......................... 6
ARTICLE III ISSUANCE OF THE BONDS................................... 6
Section 3.1. Agreement to Issue Bonds; Application of Bond Proceeds.. 6
Section 3.2. Deposit of Additional Funds by Company; Redemption of
Prior Bonds.......................................... 7
Section 3.3. Investment of Moneys in the Bond Fund and the Prior
Bonds Redemption Fund................................ 7
Section 3.4. Tax Exempt Status of Bonds.............................. 8
ARTICLE IV LOAN AND PROVISIONS FOR REPAYMENT....................... 8
Section 4.1. Loan of Bond Proceeds................................... 8
Section 4.2. Loan Repayments and Other Amounts Payable............... 8
Section 4.3. No Defense or Set-Off................................... 10
Section 4.4. Payments Pledged and Assigned........................... 10
Section 4.5. Payment of the Bonds and Other Amounts.................. 11
ARTICLE V SPECIAL COVENANTS AND AGREEMENTS........................ 11
Section 5.1. Company to Maintain its Corporate Existence; Conditions
Under Which Exceptions Permitted..................... 11
Section 5.2. Annual Statement........................................ 12
Section 5.3. Maintenance and Repair; Insurance; Taxes; Disposition... 12
Section 5.4. Recordation and Other Instruments....................... 13
Section 5.5. No Warranty by the Issuer............................... 13
Section 5.6. Agreement as to Ownership of the Project................ 13
Section 5.7. Company to Furnish Notice of Rate Period Adjustments;
Liquidity Facility Requirements; Auction Rate Period
Provisions........................................... 13
Section 5.8. Information Reporting, Etc.............................. 14
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Section 5.9. Limited Liability of Issuer............................. 14
Section 5.10. Inspection of Project................................... 15
Section 5.11. Indenture Covenants..................................... 15
ARTICLE VI EVENTS OF DEFAULT AND REMEDIES.......................... 15
Section 6.1. Events of Default Defined............................... 15
Section 6.2. Remedies on Default..................................... 17
Section 6.3. No Remedy Exclusive..................................... 17
Section 6.4. Agreement to Pay Fees and Expenses of Counsel........... 18
Section 6.5. No Additional Waiver Implied by One Waiver; Consents to
Waivers.............................................. 18
ARTICLE VII OPTIONS AND OBLIGATIONS OF COMPANY; PREPAYMENTS;
REDEMPTION OF BONDS.................................. 18
Section 7.1. Option to Prepay........................................ 18
Section 7.2. Obligation to Prepay.................................... 19
Section 7.3. Notice of Prepayment.................................... 19
ARTICLE VIII MISCELLANEOUS........................................... 19
Section 8.1. Notices................................................. 19
Section 8.2. Assignments............................................. 20
Section 8.3. Severability............................................ 20
Section 8.4. Execution of Counterparts............................... 20
Section 8.5. Amounts Remaining in Bond Fund.......................... 20
Section 8.6. Amendments, Changes and Modifications................... 20
Section 8.7. Governing Law........................................... 21
Section 8.8. Authorized Issuer and Company Representatives........... 21
Section 8.9. Term of the Agreement................................... 21
Section 8.10. Cancellation at Expiration of Term...................... 21
Section 8.11. Bond Insurance.......................................... 21
Signature................................................................ 22
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THIS FINANCING AGREEMENT made and entered into as of November 1, 2006, by
and between HUMBOLDT COUNTY, NEVADA, a political subdivision of the State of
Nevada, party of the first part (hereinafter referred to as the "Issuer"), and
SIERRA PACIFIC POWER COMPANY, a corporation duly organized and existing under
the laws of the State of Nevada, party of the second part (hereinafter referred
to as the "Company"),
WITNESSETH:
In consideration of the respective representations and agreements
hereinafter contained, the parties hereto agree as follows (provided, that in
the performance of the agreements of the Issuer herein contained, any obligation
it may thereby incur shall not constitute or give rise to a pecuniary liability
or a charge upon its general credit or against its taxing powers but shall be
payable solely out of the Revenues (as hereinafter defined) derived from this
Financing Agreement and the Bonds, as hereinafter defined):
ARTICLE I
DEFINITIONS
The following terms shall have the meanings specified in this Article
unless the context clearly requires otherwise. The singular shall include the
plural and the masculine shall include the feminine.
"Act" means the County Economic Development Revenue Bond Law, as amended,
contained in Sections 244A.669 to 244A.763, inclusive, of the Nevada Revised
Statutes.
"Administrative Expenses" means the reasonable and necessary expenses
(including the reasonable value of employee services and fees of Counsel)
incurred by the Issuer in connection with the Bonds, this Agreement, the
Indenture and any transaction or event contemplated by this Agreement or the
Indenture.
"Agreement" means this Financing Agreement by and between the Issuer and
the Company, as from time to time amended and supplemented.
"Auction Agent" means the auction agent appointed in accordance with the
provisions of the Indenture.
"Authorized Company Representative" means any person who, at the time,
shall have been designated to act on behalf of the Company by a written
certificate furnished to the Issuer, the Remarketing Agent and the Trustee
containing the specimen signature of such person and signed on behalf of the
Company by any officer of the Company. Such certificate may designate an
alternate or alternates.
"Authorized Issuer Representative" means any person at the time designated
to act on behalf of the Issuer by a written certificate furnished to the Company
and the Trustee containing the specimen signature of such person and signed on
behalf of the Issuer by its Chairman. Such certificate may designate an
alternate or alternates.
"Bankruptcy Code" means the United States Bankruptcy Reform Act of 1978, as
amended from time to time, or any substitute or replacement legislation.
"Bond" or "Bonds" means the Issuer's bonds identified in Section 2.02 of
the Indenture.
"Bond Counsel" means the Counsel who renders the opinion as to the
tax-exempt status of interest on the Bonds or other nationally recognized
municipal bond counsel mutually acceptable to the Issuer and the Company.
"Bond Fund" means the fund created by Section 6.02 of the Indenture.
"Code" means the United States Internal Revenue Code of 1986, as amended,
and regulations promulgated or proposed thereunder and, to the extent applicable
to the Bonds or the Prior Bonds, the 1954 Code.
"Company" means Sierra Pacific Power Company, a Nevada corporation, and its
successors and assigns and any surviving, resulting or transferee corporation as
permitted in Section 5.1 hereof.
"Counsel" means an attorney at law or a firm of attorneys (who may be an
employee of or counsel to the Issuer or the Company or the Trustee) duly
admitted to the practice of law before the highest court of any state of the
United States of America or of the District of Columbia.
"Delivery Agreement" means the Delivery Agreement dated the Dated Date,
between the Company and the Trustee, as amended, supplemented or restated from
time to time, pursuant to which the Company will issue to the Trustee the G&R
Notes at the time of the initial authentication and delivery of the Bonds.
"Extraordinary Services" and "Extraordinary Expenses" means all services
rendered and all expenses (including fees and expenses of Counsel) incurred
under the Indenture and the Tax Agreement other than Ordinary Services and
Ordinary Expenses.
"Force Majeure" means acts of God, strikes, lockouts or other industrial
disturbances; acts of public enemies; orders or restraints of any kind of the
governments of the United States or of the State, or any of their departments,
agencies or officials, or any civil or military authority; insurrections; riots;
landslides; lightning; earthquakes; fires; tornadoes; volcanoes; storms;
droughts; floods; explosions, breakage, or malfunction or accident to machinery,
transmission lines, pipes or canals, even if resulting from negligence; civil
disturbances; or any other cause not reasonably within the control of the
Company.
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"G&R Indenture" means the General and Refunding Mortgage Indenture dated as
of May 1, 2001 between the Company and the G&R Trustee, as amended and
supplemented.
"G&R Notes" means the Company's $49,750,000 General and Refunding Mortgage
Note, Series N, No. N-1, due October 1, 2029.
"G&R Trustee" means The Bank of New York, as trustee under the G&R
Indenture or any successor trustee.
"Governing Body" means the Board of County Commissioners of the Issuer.
"Hereof," "herein," "hereunder" and other words of similar import refer to
this Agreement as a whole.
"Indenture" means the Indenture of Trust relating to this Agreement between
the Issuer and The Bank of New York, as Trustee, of even date herewith, pursuant
to which the Bonds are authorized to be issued, including any indentures
supplemental thereto or amendatory thereof.
"Issuer" means Humboldt County, Nevada, and any successor body to the
duties or functions of the Issuer.
"1954 Code" means the Internal Revenue Code of 1954, as amended, and the
applicable regulations thereunder.
"Ordinary Services" and "Ordinary Expenses" means those services normally
rendered and those expenses including fees and expenses of Counsel, normally
incurred by a trustee or paying agent under instruments similar to the Indenture
and the Tax Agreement.
"Owner" or "owner of Bonds" means the Person or Persons in whose name or
names a Bond shall be registered on books of the Issuer kept by the Registrar
for that purpose in accordance with the terms of the Indenture.
"Person" means natural persons, firms, partnerships, associations,
corporations, trusts and public bodies.
"Prior Bonds" means the Series 1987 Bonds and the Series 1992 Bonds.
"Prior Bond Funds" means the Series 1987 Bond Fund and the Series 1992 Bond
Fund.
"Prior Indentures" means the Series 1987 Indenture and the Series 1992
Indenture.
"Prior Trustees" means the Series 1987 Trustee and the Series 1992 Trustee.
"Project" means the Project as defined in the Project Certificate.
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"Project Certificate" means the Company's Project and Refunding
Certificate, delivered concurrently with the issuance of the Bonds, with respect
to certain facts which are within the knowledge of the Company and certain
reasonable assumptions of the Company, to enable Chapman and Cutler LLP, as Bond
Counsel, to determine that interest on the Bonds is not includable in the gross
income of the Owners of the Bonds for federal income tax purposes.
"Rebate Fund" means the Rebate Fund, if any, created and established
pursuant to the Tax Agreement.
"Regulated Utility Company" means a corporation (or a limited liability
company) engaged in the distribution of electricity, gas and/or water and which
is regulated by the public utility commission where its primary distribution
business is located.
"Remarketing Agent" means the remarketing agent, if any, appointed in
accordance with Section 4.08 of the Indenture and any permitted successor
thereto.
"Reorganization" means any reorganization, consolidation or merger of the
Company or its affiliates, or any transfer or lease of a substantial portion of
the assets of the Company or its affiliates, as a result of which the obligor
under the Agreement or the obligor on the G&R Notes ceases to be a Regulated
Utility Company.
"Series 1987 Bond Fund" means the fund established pursuant to Section 502
of the Series 1987 Indenture.
"Series 1987 Bonds" means the Issuer's Variable Rate Demand Pollution
Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series
1987, currently outstanding in the aggregate principal amount of $39,500,000.
"Series 1987 Indenture" means the Indenture of Trust dated March 1, 1987
between the Issuer and the Series 1987 Trustee, as trustee, pursuant to which
the Series 1987 Bonds were issued.
"Series 1987 Trustee" means The Bank of New York Trust Company, N.A., as
current trustee under the Series 1987 Indenture.
"Series 1992 Bond Fund" means the fund established pursuant to Section 5.02
of the Series 1992 Indenture.
"Series 1992 Bonds" means the Issuer's Pollution Control Refunding Revenue
Bonds (Sierra Pacific Power Company Project) Series 1992A, currently outstanding
in the aggregate principal amount of $10,250,000.
"Series 1992 Indenture" means the Indenture of Trust dated July 1, 1992
between the Issuer and the Series 1992 Trustee, as trustee, pursuant to which
the Series 1992 Bonds were issued.
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"Series 1992 Trustee" means The Bank of New York, as current trustee under
the Series 1992 Indenture.
"State" means the State of Nevada.
"Tax Agreement" means the Tax Exemption Certificate and Agreement with
respect to the Bonds, dated the date of delivery of the Bonds, among the
Company, the Issuer and the Trustee, as from time to time amended and
supplemented.
"Trust Estate" means the property conveyed to the Trustee pursuant to the
Granting Clauses of the Indenture.
"Trustee" means The Bank of New York, as Trustee under the Indenture, and
any successor Trustee appointed pursuant to Section 10.06 or 10.09 of the
Indenture at the time serving as Trustee thereunder, and any separate or
co-trustee serving as such thereunder.
All other terms used herein which are defined in the Indenture shall have
the same meanings assigned them in the Indenture unless the context otherwise
requires.
ARTICLE II
REPRESENTATIONS
SECTION 2.1. REPRESENTATIONS AND COVENANTS BY THE ISSUER. The Issuer makes
the following representations and covenants as the basis for the undertakings on
its part herein contained:
(a) The Issuer is a duly organized and existing political subdivision
of the State of Nevada. Under the provisions of the Act, the Issuer is
authorized to enter into the transactions contemplated by this Agreement,
the Indenture and the Tax Agreement and to carry out its obligations
hereunder and thereunder. The Issuer has duly authorized the execution and
delivery of this Agreement, the Indenture and the Tax Agreement.
(b) The Bonds are to be issued under and secured by the Indenture,
pursuant to which certain of the Issuer's interests in this Agreement and
the Revenues derived by the Issuer pursuant to this Agreement will be
pledged and assigned as security for payment of the principal of, premium,
if any, and interest on, the Bonds.
(c) The Governing Body of the Issuer has found that the issuance of
the Bonds will further the public purposes of the Act.
(d) The Issuer has not assigned and will not assign any of its
interests in this Agreement other than pursuant to the Indenture.
(e) No member of the Governing Body of the Issuer, nor any other
officer of the Issuer, has any interest, financial (other than ownership of
less than one-tenth of one
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percent (.1%) of the publicly traded securities issued by the Company or
its affiliated corporations), employment or other, in the Company or in the
transactions contemplated hereby.
SECTION 2.2. REPRESENTATIONS BY THE COMPANY. The Company makes the
following representations as the basis for the undertakings on its part herein
contained:
(a) The Company is a corporation duly incorporated under the laws of
the State and is in good standing in the State, is qualified to do business
as a foreign corporation in all other states and jurisdictions wherein the
nature of the business transacted by the Company or the nature of the
property owned or leased by it makes such licensing or qualification
necessary, and has the power to enter into and by proper corporate action
has been duly authorized to execute and deliver this Agreement and the Tax
Agreement.
(b) Neither the execution and delivery of this Agreement or the Tax
Agreement, the consummation of the transactions contemplated hereby and
thereby, nor the fulfillment of or compliance with the terms and conditions
of this Agreement and the Tax Agreement, conflicts with or results in a
breach of any of the terms, conditions or provisions of any corporate
restriction or any agreement or instrument to which the Company is now a
party or by which it is bound, or constitutes a default under any of the
foregoing, or results in the creation or imposition of any lien, charge or
encumbrance whatsoever upon any of the property or assets of the Company
under the terms of any instrument or agreement other than the Indenture.
(c) The statements, information and descriptions contained in the
Project Certificate and the Tax Agreement, as of the date hereof and at the
time of the delivery of the Bonds to the Underwriter, are and will be true,
correct and complete, do not and will not contain any untrue statement or
misleading statement of a material fact, and do not and will not omit to
state a material fact required to be stated therein or necessary to make
the statements, information and descriptions contained therein, in the
light of the circumstances under which they were made, not misleading.
ARTICLE III
ISSUANCE OF THE BONDS
SECTION 3.1. AGREEMENT TO ISSUE BONDS; APPLICATION OF BOND PROCEEDS. In
order to provide funds to lend to the Company to refund the Prior Bonds as
provided in Section 4.1 hereof, the Issuer agrees that it will issue under the
Indenture, sell and cause to be delivered to the Underwriter, its Bonds in the
aggregate principal amount of $49,750,000, bearing interest and maturing as set
forth in the Indenture. The Issuer will thereupon deposit the proceeds received
from the sale of the Bonds as follows: (1) in the Bond Fund, a sum equal to the
accrued interest, if any, paid by the Underwriter; and (2) $49,750,000 in the
Prior Bonds Redemption Fund to be remitted by the Trustee to the Prior Trustees
for deposit in the Prior Bond Funds to be used to pay to the owners thereof the
principal of the Prior Bonds upon redemption thereof.
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SECTION 3.2. DEPOSIT OF ADDITIONAL FUNDS BY COMPANY; REDEMPTION OF PRIOR
BONDS. The Company covenants that such additional amounts as may be required to
redeem the Prior Bonds in accordance with Section 3.1 hereof will be timely
deposited with the Prior Trustee pursuant to the Prior Indentures for such
purpose. Income derived from the investment of the proceeds of the Bonds
deposited in the two accounts of the Prior Bonds Redemption Fund will be used,
to the extent available, to satisfy the obligations of the Company specified in
this Section 3.2. The Company covenants that it will cause the Prior Bonds to be
redeemed within 90 days after the issuance and delivery of the Bonds.
SECTION 3.3. INVESTMENT OF MONEYS IN THE BOND FUND AND THE PRIOR BONDS
REDEMPTION FUND. Except as otherwise herein provided, any moneys held as a part
of the Bond Fund and the Prior Bonds Redemption Fund shall be invested or
reinvested by the Trustee at the specific written direction of an Authorized
Company Representative as to specific investments, to the extent permitted by
law, in:
(a) bonds or other obligations of the United States of America;
(b) bonds or other obligations, the payment of the principal of and
interest on which is unconditionally guaranteed by the United States of
America;
(c) obligations issued or guaranteed as to principal and interest by
any agency or person controlled or supervised by and acting as an
instrumentality of the United States of America pursuant to authority
granted by the Congress of the United States of America;
(d) obligations issued or guaranteed by any state of the United States
of America, or any political subdivision of any such state, or in funds
consisting of such obligations to the extent described in Section
1.148-8(e)(3)(iii) of the 1992 Treasury Regulations;
(e) prime commercial paper;
(f) prime finance company paper;
(g) bankers' acceptances drawn on and accepted by commercial banks;
(h) repurchase agreements fully secured by obligations issued or
guaranteed as to principal and interest by the United States of America or
by any person controlled or supervised by and acting as an instrumentality
of the United States of America pursuant to authority granted by the
Congress of the United States of America;
(i) certificates of deposit issued by commercial banks, including
banks domiciled outside of the United States of America; and
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(j) units of taxable government money market portfolios composed of
obligations guaranteed as to principal and interest by the United States of
America or repurchase agreements fully collateralized by such obligations.
The investments so purchased shall be held by the Trustee and shall be
deemed at all times a part of the fund and the accounts therein, if any, for
which they were made and the interest accruing thereon and any profit realized
therefrom shall be credited to such fund and the accounts therein, if any,
subject to the provisions of the Tax Agreement. The Company agrees that to the
extent any moneys in the Bond Fund represent moneys held for the payment of
particular Bonds, or to the extent that any moneys are held for the payment of
the purchase price of Bonds pursuant to Article IV of the Indenture, such moneys
shall not be invested.
SECTION 3.4. TAX EXEMPT STATUS OF BONDS. The Company covenants and agrees
that it has not taken or permitted and will not take or permit any action which
results in interest paid on the Bonds being included in gross income of the
holders or beneficial owners of the Bonds for purposes of federal income
taxation (other than a holder or beneficial owner who is a "substantial user" of
the Project or a "related person" within the meaning of Section 103(b)(13) of
the 1954 Code). The Company covenants that none of the proceeds of the Bonds or
the payments to be made under this Agreement, or any other funds which may be
deemed to be proceeds of the Bonds pursuant to Section 148(a) of the Code, will
be invested or used in such a way, and that no actions will be taken or not
taken, as to cause the Bonds to be treated as "arbitrage bonds" within the
meaning of Section 148(a) of the Code. Without limiting the generality of the
foregoing, the Company covenants and agrees that it will comply with the
provisions of the Tax Agreement and the Project Certificate.
ARTICLE IV
LOAN AND PROVISIONS FOR REPAYMENT
SECTION 4.1. LOAN OF BOND PROCEEDS. (a) The Issuer agrees, upon the terms
and conditions in this Agreement, to lend to the Company the proceeds (exclusive
of accrued interest, if any) received by the Issuer from the sale of the Bonds
in order to refund the Prior Bonds, and the Company agrees to apply the gross
proceeds of such loan to the refunding of the Prior Bonds as set forth in
Sections 3.1 and 3.2 hereof.
(b) The Issuer and the Company expressly reserve the right to enter
into, to the extent permitted by law, an agreement or agreements other than
this Agreement, with respect to the issuance by the Issuer, under an
indenture or indentures other than the Indenture, of obligations to provide
additional funds to refund all or any principal amount of the Bonds.
SECTION 4.2. LOAN REPAYMENTS AND OTHER AMOUNTS PAYABLE. (a) On each date
provided in or pursuant to the Indenture for the payment (whether at maturity or
upon redemption or acceleration) of principal of, and premium, if any, and
interest on, the Bonds, until the principal of, and premium, if any, and
interest on, the Bonds shall have been fully paid or provision for the payment
thereof shall have been made in accordance with the Indenture, the Company shall
pay to the Trustee in immediately available funds, for deposit in the Bond Fund,
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as a repayment installment of the loan of the proceeds of the Bonds pursuant to
Section 4.1(a) hereof, a sum equal to the amount payable on such date (whether
at maturity or upon redemption or acceleration) as principal of, and premium, if
any, and interest on, the Bonds as provided in the Indenture; provided, however,
that the obligation of the Company to make any such repayment installment shall
be reduced by the amount of any moneys then on deposit in the Bond Fund and
available for such payment; and provided further, that the obligation of the
Company to make any such payment shall be deemed to be satisfied and discharged
to the extent provided for under a liquidity facility (if applicable) or under
the G&R Notes.
(b) The Company shall pay to the Trustee amounts equal to the amounts
to be paid by the Trustee for the purchase of Bonds pursuant to Article IV
of the Indenture. Such amounts shall be paid by the Company to the Trustee
in immediately available funds on the date such payments pursuant to
Section 4.05 of the Indenture are to be made; provided, however, that the
obligation of the Company to make any such payment shall be deemed to be
satisfied and discharged to the extent moneys are available from the source
described in clause (i) of Section 4.05(a) of the Indenture and to the
extent moneys are available under any liquidity facility (if applicable).
(c) The Company agrees to pay to the Trustee (i) the fees of the
Trustee for the Ordinary Services rendered by it and an amount equal to the
Ordinary Expenses incurred by it under the Indenture and the Tax Agreement,
as and when the same become due, and (ii) the reasonable fees, charges and
expenses of the Trustee for reasonable Extraordinary Services and
Extraordinary Expenses, as and when the same become due, incurred under the
Indenture and the Tax Agreement. The Company agrees that the Trustee, its
officers, agents, servants and employees, shall not be liable for, and
agrees that it will at all times indemnify and hold harmless the Trustee,
its officers, agents, servants and employees against, and pay all expenses
of the Trustee, its officers, agents, servants and employees, relating to
any lawsuit, proceeding or claim and resulting from any action or omission
taken or made by or on behalf of the Trustee, its officers, agents,
servants and employees pursuant to this Agreement, the Indenture or the Tax
Agreement, that may be occasioned by any cause (other than the negligence
or willful misconduct of the Trustee, its officers, agents, servants and
employees). In case any action shall be brought against the Trustee in
respect of which indemnity may be sought against the Company, the Trustee
shall promptly notify the Company in writing and the Company shall be
entitled to assume control of the defense thereof, including the employment
of Counsel reasonably satisfactory to the Trustee and the payment of all
expenses. The Trustee shall have the right to employ separate Counsel in
any such action and participate in the defense thereof, but the fees and
expenses of such Counsel shall be paid by the Trustee unless (i) the
employment of such Counsel has been authorized by the Company, (ii) the
Trustee has determined (which determination may be based upon an opinion of
counsel delivered to the Trustee and furnished to the Company) that there
may be a conflict of interest of such Counsel retained by the Company
between the Company and the Trustee in the conduct of such defense, (iii)
the Company ceases or terminates the employment of such Counsel retained by
the Company or (iv) such Counsel retained by the Company withdraws with
respect to such defense. The Company shall not be liable for any settlement
of any such action without its consent, but if any such action is settled
with the consent of the Company or if there be final judgment for the
plaintiff in any such action, the Company agrees to indemnify and hold
harmless the Trustee from and against any loss or
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liability by reason of such settlement or final judgment. The Company
agrees that the indemnification provided herein shall survive the
termination of this Agreement or the Indenture or the resignation of the
Trustee. For purposes of this Section 4.2(c), the Trustee is deemed a third
party beneficiary of this Agreement.
(d) The Company agrees to pay all costs incurred in connection with
the issuance of the Bonds from sources other than Bond proceeds and the
Issuer shall have no obligation with respect to such costs.
(e) The Company agrees to indemnify and hold harmless the Issuer and
any member, officer, official or employee of the Issuer against any and all
losses, costs, charges, expenses, judgments and liabilities created by or
arising out of this Agreement, the Indenture, the Remarketing Agreement,
the Auction Agreement, the Bond Purchase Agreement, any Broker-Dealer
Agreement or the Tax Agreement or otherwise incurred in connection with the
issuance of the Bonds. The Issuer may submit to the Company periodic
statements, not more frequently than monthly, for its Administrative
Expenses and the Company shall make payment to the Issuer of the full
amount of each such statement within 30 days after the Company receives
such statement.
(f) The Company agrees to pay (i) to the Remarketing Agent the
reasonable fees, charges and expenses of such Remarketing Agent and (ii) to
the Auction Agent the reasonable fees, charges and expenses of such Auction
Agent, and the Issuer shall have no obligation or liability with respect to
the payment of any such fees, charges or expenses.
(g) In the event the Company shall fail to make any of the payments
required by (a) or (b) of this Section 4.2, the payment so in default shall
continue as an obligation of the Company until the amount in default shall
have been fully paid and the Company will pay interest to the extent
permitted by law, on any overdue amount at the rate of interest borne by
the Bonds on the date on which such amount became due and payable until
paid. In the event that the Company shall fail to make any of the payments
required by (c), (d), (e) or (f) of this Section 4.2, the payment so in
default shall continue as an obligation of the Company until the amount in
default shall have been fully paid, and the Company agrees to pay the same
with interest thereon to the extent permitted by law at a rate 1% above the
rate of interest then charged by the Trustee on 90-day commercial loans to
its prime commercial borrowers until paid.
SECTION 4.3. NO DEFENSE OR SET-OFF. The obligation of the Company to make
the payments pursuant to this Agreement shall be absolute and unconditional
without defense or set-off by reason of any default by the Issuer under this
Agreement or under any other agreement between the Company and the Issuer or for
any other reason, it being the intention of the parties that the payments
required hereunder will be paid in full when due without any delay or diminution
whatsoever.
SECTION 4.4. PAYMENTS PLEDGED AND ASSIGNED. It is understood and agreed
that all payments required to be made by the Company pursuant to Section 4.2
hereof (except payments made to the Trustee pursuant to Section 4.2(c) hereof,
to the Remarketing Agent and the Auction Agent pursuant to Section 4.2(f)
hereof, to the Issuer pursuant to Section 4.2(e) hereof and to any
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or all the Issuer and the Trustee and the Remarketing Agent pursuant to Section
4.2(g) hereof) and certain rights of the Issuer hereunder are pledged and
assigned by the Indenture. The Company consents to such pledge and assignment.
The Issuer hereby directs the Company and the Company hereby agrees to pay or
cause to be paid to the Trustee all said amounts except payments to be made to
the Remarketing Agent and the Auction Agent pursuant to Section 4.2(f) hereof
and payments to be made to the Issuer pursuant to Sections 4.2(e) and (g)
hereof. The Project will not constitute any part of the security for the Bonds,
except to the extent that the Trustee as holder of G&R Notes has a lien on
property under the G&R Indenture.
SECTION 4.5. PAYMENT OF THE BONDS AND OTHER AMOUNTS. The Bonds and interest
and premium, if any, thereon shall be payable solely from (i) payments made by
the Company to the Trustee under Section 4.2(a) hereof and (ii) other moneys on
deposit in the Bond Fund and available therefor.
Payments of principal of, and premium, if any, or interest on, the Bonds
with moneys in the Bond Fund constituting proceeds from the sale of the Bonds or
earnings on investments made under the provisions of the Indenture shall be
credited against the obligation to pay required by Section 4.2(a) hereof.
Whenever any Bonds are redeemable in whole or in part at the option of the
Company, the Trustee, on behalf of the Issuer, shall redeem the same upon the
request of the Company and such redemption (unless conditional) shall be made
from payments made by the Company to the Trustee under Section 4.2(a) hereof
equal to the redemption price of such Bonds.
Whenever payment or provision therefor has been made in respect of the
principal of, or premium, if any, or interest on, all or any portion of the
Bonds in accordance with the Indenture (whether at maturity or upon redemption
or acceleration or upon provision for payment in accordance with Article VIII of
the Indenture), payments shall be deemed paid to the extent such payment or
provision therefor has been made and is considered to be a payment of principal
of, or premium, if any, or interest on, such Bonds. If such Bonds are thereby
deemed paid in full, the Trustee shall notify the Company and the Issuer that
such payment requirement has been satisfied. Subject to the foregoing, or unless
the Company is entitled to a credit under this Agreement or the Indenture, all
payments shall be in the full amount required by Section 4.2(a) hereof.
ARTICLE V
SPECIAL COVENANTS AND AGREEMENTS
SECTION 5.1. COMPANY TO MAINTAIN ITS CORPORATE EXISTENCE; CONDITIONS UNDER
WHICH EXCEPTIONS PERMITTED. The Company agrees that during the term of this
Agreement, it will maintain its corporate existence and its good standing in the
State, will not dissolve or otherwise dispose of all or substantially all of its
assets and will not consolidate with or merge into another corporation unless
the acquirer of its assets or the corporation with which it shall consolidate or
into which it shall merge shall (i) be a corporation organized under the laws of
one of the states of the United States of America, (ii) be qualified to do
business in the State, and
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(iii) assume in writing all of the obligations of the Company under this
Agreement and the Tax Agreement. Any transfer of all or substantially all of the
Company's generation assets shall not be deemed to constitute a "disposition of
all or substantially all of the Company's assets" within the meaning of the
preceding paragraph. Any such transfer of the Company's generation assets shall
not relieve the Company of any of its obligations under this Agreement.
The Company hereby agrees that so long as any of the Bonds are insured by a
Bond Insurance Policy issued by the Bond Insurer and the Bond Insurer shall not
have failed to comply with its payment obligations under such Policy, in the
event of a Reorganization, unless otherwise consented to by the Bond Insurer,
the obligations of the Company under, and in respect of, the Bonds, the G&R
Notes, the G&R Indenture and the Agreement shall be assumed by, and shall become
direct and primary obligations of, a Regulated Utility Company such that at all
times the obligor under this Agreement and the obligor on the G&R Notes is a
Regulated Utility Company. The Company shall deliver to the Bond Insurer a
certificate of the president, any vice president or the treasurer and an opinion
of counsel reasonably acceptable to the Bond Insurer stating in each case that
such Reorganization complies with the provisions of this paragraph.
The Company need not comply with any of the provisions of this Section 5.1
if, at the time of such merger or consolidation, the Bonds will be defeased as
provided in Article VIII of the Indenture. The Company need not comply with the
provisions of the second paragraph of this Section 5.1 if the Bonds are redeemed
as provided in Section 3.01(B)(3) of the Indenture or if the Bond Insurance
Policy is terminated as described in Section 3.06 of the Indenture in connection
with a purchase of the Bonds by the Company in lieu of their redemption.
SECTION 5.2. ANNUAL STATEMENT. The Company agrees to have an annual audit
made by its regular independent certified public accountants and to furnish the
Trustee (within 30 days after receipt by the Company) with a balance sheet and
statement of income and surplus showing the financial condition of the Company
and its consolidated subsidiaries, if any, at the close of each fiscal year and
the results of operations of the Company and its consolidated subsidiaries, if
any, for each fiscal year, accompanied by a report of said accountants that such
statements have been prepared in accordance with generally accepted accounting
principles. The Company's obligations under this Section 5.2 may be satisfied by
delivering a copy of the Company's Annual Report on Form 10-K to the Trustee
within 10 days after it is filed with the Securities and Exchange Commission.
Delivery of such reports, information and documents to the Trustee is for
informational purposes only and the Trustee's receipt of such shall not
constitute constructive notice of any information contained therein or
determinable from information contained therein, including the Company's
compliance with any of its covenants hereunder (as to which the Trustee is
entitled to rely exclusively on officer's certificates).
SECTION 5.3. MAINTENANCE AND REPAIR; INSURANCE; TAXES; DISPOSITION. For so
long as the Company shall own the Project, (i) the Company shall maintain or
cause to be maintained the Project in good repair and keep it properly insured
and shall promptly pay or cause to be paid all costs thereof, and (ii) the
Company shall promptly pay or cause to be paid all installments of
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taxes, installments of special assessments, and all governmental, utility and
other charges with respect to the Project, when due. The Company may, at its own
expense and in its own name in good faith contest or appeal any such taxes,
assessments or other charges, or installments thereof, but shall not permit any
such taxes, assessments or other charges, or installments thereof, to remain
unpaid if such nonpayment shall subject the Project or any part thereof to loss
or forfeiture. The Company, subject to the provisions of Section 3.4 hereof, is
not required by this Agreement to operate, or cause to be operated, any portion
of the Project after the Company shall deem in its discretion that such
continued operation by the Company is not advisable, and in such event the
Company may sell, lease or retire all or any such portion of the Project.
Subject to the provisions of Section 3.4 hereof, the net proceeds from such
sale, lease or other disposition, if any, shall belong to, and may be used for
any lawful purpose by, the Company. Upon disposition of the Project in its
entirety by the Company in accordance with this Section 5.3, the Company shall
be discharged from its obligations to operate, maintain, repair and insure the
Project as set forth in this Section 5.3. Any such sale, lease or other
disposition shall comply with the requirements of the Tax Agreement. Under any
and all circumstances, the Issuer shall have no obligation whatsoever with
respect to the operation, maintenance, repair or insurance of the Project.
SECTION 5.4. RECORDATION AND OTHER INSTRUMENTS. The Company shall cause
such security agreements, financing statements and all supplements thereto and
other instruments as may be required from time to time to be kept, to be
recorded and filed in such manner and in such places as may be required by law
in order to fully preserve, protect and perfect the security of the Owners of
the Bonds and the rights of the Trustee, and to perfect the security interest
created by the Indenture. The Company agrees to abide by the provisions of
Section 5.11 of the Indenture to the extent applicable to the Company.
SECTION 5.5. NO WARRANTY BY THE ISSUER. The Issuer makes no warranty,
either express or implied, as to the Project or that it will be suitable for the
purposes of the Company or needs of the Company.
SECTION 5.6. AGREEMENT AS TO OWNERSHIP OF THE PROJECT. The Issuer and the
Company agree that title to the Project shall not be in the Issuer, and that the
Issuer shall have no interest in the Project.
SECTION 5.7. COMPANY TO FURNISH NOTICE OF RATE PERIOD ADJUSTMENTS;
LIQUIDITY FACILITY REQUIREMENTS; AUCTION RATE PERIOD PROVISIONS. The Company is
hereby granted the option to designate from time to time changes in Rate Periods
(and to rescind such changes) in the manner and to the extent set forth in
Section 2.03 of the Indenture. In the event the Company elects to exercise any
such option, the Company agrees that it shall cause notices of adjustments of
Rate Periods (or rescissions thereof) to be given to the Issuer, the Trustee and
the Remarketing Agent in accordance with Section 2.03(a), (b), (c), (d) or (e)
of the Indenture, and a copy of each such notice shall also be given at such
time to S&P and Moody's.
The Company hereby agrees that, so long as the Bonds are insured by a Bond
Insurance Policy issued by the Bond Insurer and notwithstanding the provisions
of Section 2.03 of the Indenture, it shall not give notice of its intention to
adjust the Rate Period for the Bonds to a
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Daily Rate Period, a Weekly Rate Period or a Flexible Rate Period until the
Company shall provide a liquidity facility reasonably acceptable to the Bond
Insurer from a liquidity facility provider reasonably acceptable to the Bond
Insurer in accordance with the Bond Insurer's liquidity facility requirements to
be effective on the related date of adjustment.
If during any Auction Rate Period (i) consisting of Auction Periods of 35
days or less, the Bonds shall bear interest at the Maximum Interest Rate for a
period in excess of 180 days, or (ii) consisting of one Auction Period of 180
days or more, the Bonds shall bear interest at the Maximum Interest Rate for
such Period, the Company shall notify the Bond Insurer in writing of such event
and agrees to cooperate with the Bond Insurer to take all steps reasonably
necessary to adjust the Rate Period on the Bonds as soon as reasonably
practicable in accordance with the provisions of the Indenture to the Rate
Period which the Remarketing Agent advises the Company and the Bond Insurer will
be the lowest interest rate (taking into account all relevant costs) which would
enable the Remarketing Agent to sell all the Bonds on the date of such
adjustment at a price equal to 100% of the principal amount thereof (the "Lowest
Interest Rate Period"). If at such time the Company shall be in default under
the Agreement but the Bond Insurer shall not have failed to comply with its
payment obligations under the Bond Insurance Policy, the Bond Insurer may, in
its discretion, direct the Company to provide notice of the adjustment of the
Rate Period on the Bonds to the Lowest Interest Rate Period in accordance with
the provisions of Section 2.03 of the Indenture.
SECTION 5.8. INFORMATION REPORTING, ETC. The Issuer covenants and agrees
that, upon the direction of the Company or Bond Counsel, it will mail or cause
to be mailed to the Secretary of the Treasury (or his designee as prescribed by
regulation, currently the Internal Revenue Service Center, Ogden, Utah) a
statement setting forth the information required by Section 149(e) of the Code,
which statement shall be in the form of the Information Return for Tax-Exempt
Private Activity Bond Issues (Form 8038) of the Internal Revenue Service (or any
successor form) and which shall be completed by the Company and Bond Counsel
based in part upon information supplied by the Company and Bond Counsel.
SECTION 5.9. LIMITED LIABILITY OF ISSUER. Any obligation or liability of
the Issuer created by or arising out of this Agreement or otherwise incurred in
connection with the issuance of the Bonds (including without limitation any
liability created by or arising out of the representations, warranties or
covenants set forth herein or otherwise) shall not impose a debt or pecuniary
liability upon the Issuer or the State or any political subdivision thereof, or
a charge upon the general credit or taxing powers of any of the foregoing, but
shall be payable solely out of the Revenues or other amounts payable by the
Company to the Issuer hereunder or otherwise (including without limitation any
amounts derived from indemnifications given by the Company).
Neither the issuance of the Bonds nor the delivery of this Agreement shall,
directly or indirectly or contingently, obligate the Issuer or the State or any
political subdivision thereof to levy any form of taxation therefor or to make
any appropriation for their payment. Nothing in the Bonds or in the Indenture or
this Agreement or the proceedings of the Issuer authorizing the Bonds or in the
Act or in any other related document shall be construed to authorize the Issuer
to create a debt of the Issuer or the State or any political subdivision thereof
within the meaning of
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any constitutional or statutory provision of the State. The principal of, and
premium, if any, and interest on, the Bonds shall be payable solely from the
funds pledged for their payment in accordance with the Indenture and available
therefor under this Agreement. Neither the State nor any political subdivision
thereof shall in any event be liable for the payment of the principal of,
premium, if any, or interest on, the Bonds or for the performance of any pledge,
obligation or agreement of any kind whatsoever which may be undertaken by the
Issuer. No breach of any such pledge, obligation or agreement may impose any
pecuniary liability upon the Issuer or the State or any political subdivision
thereof, or any charge upon the general credit or against the taxing power of
the Issuer or the State or any political subdivision thereof.
SECTION 5.10. INSPECTION OF PROJECT. The Company agrees that the Issuer and
the Trustee and their duly authorized representatives shall have the right at
all reasonable times to enter upon and examine and inspect the Project property
and shall also be permitted, at all reasonable times, to examine the books and
records of the Company insofar as they relate to the Project.
SECTION 5.11. INDENTURE COVENANTS. The Company covenants to observe and
perform all of the obligations imposed on it under the Indenture.
ARTICLE VI
EVENTS OF DEFAULT AND REMEDIES
SECTION 6.1. EVENTS OF DEFAULT DEFINED. The following shall be "events of
default" under this Agreement and the terms "event of default" or "default"
shall mean, whenever they are used in this Agreement, any one or more of the
following events:
(a) Failure by the Company to pay when due any amounts required to be
paid under Section 4.2(a) hereof, which failure results in an event of
default under subparagraph (a) or (b) of Section 9.01 of the Indenture; or
(b) Failure by the Company to pay or cause to be paid any payment
required to be paid under Section 4.2(b) hereof, which failure results in
an event of default under subparagraph (c) of Section 9.01 of the
Indenture; or
(c) Failure by the Company to observe and perform any covenant,
condition or agreement on its part to be observed or performed in this
Agreement, other than as referred to in (a) and (b) above, for a period of
90 days after written notice, specifying such failure and requesting that
it be remedied and stating that such notice is a "Notice of Default"
hereunder, given to the Company by the Trustee or to the Company and the
Trustee by the Issuer, unless the Issuer and the Trustee shall agree in
writing to an extension of such time prior to its expiration; provided,
however, if the failure stated in the notice cannot be corrected within the
applicable period, the Issuer and the Trustee will not unreasonably
withhold their consent to an extension of such time if corrective action is
instituted within the applicable period and diligently pursued until the
failure is corrected and such corrective action or diligent pursuit is
evidenced to the Trustee by a certificate of an Authorized Company
Representative; or
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(d) A proceeding or case shall be commenced, without the application
or consent of the Company, in any court of competent jurisdiction seeking
(i) liquidation, reorganization, dissolution, winding-up or composition or
adjustment of debts, (ii) the appointment of a trustee, receiver,
custodian, liquidator or the like of the Company or of all or any
substantial part of its assets, or (iii) similar relief under any law
relating to bankruptcy, insolvency, reorganization, winding-up or
composition or adjustment of debts, and such proceeding or cause shall
continue undismissed, or an order, judgment, or decree approving or
ordering any of the foregoing shall be entered and shall continue in effect
for a period of 90 days; or an order for relief against the Company shall
be entered against the Company in an involuntary case under the Bankruptcy
Code (as now or hereafter in effect) or other applicable law; or
(e) The Company shall admit in writing its inability to pay its debts
generally as they become due or shall file a petition in voluntary
bankruptcy or shall make any general assignment for the benefit of its
creditors, or shall consent to the appointment of a receiver or trustee of
all or substantially all of its property, or shall commence a voluntary
case under the Bankruptcy Code (as now or hereafter in effect), or shall
file in any court of competent jurisdiction a petition seeking to take
advantage of any other law relating to bankruptcy, insolvency,
reorganization, winding-up or composition or adjustment of debts, or shall
fail to controvert in a timely or appropriate manner, or acquiesce in
writing to, any petition filed against it in an involuntary case under such
Bankruptcy Code or other applicable law; or
(f) Dissolution or liquidation of the Company; provided that the term
"dissolution or liquidation of the Company" shall not be construed to
include the cessation of the corporate existence of the Company resulting
either from a merger or consolidation of the Company into or with another
corporation or a dissolution or liquidation of the Company following a
transfer of all or substantially all of its assets as an entirety, under
the conditions permitting such actions contained in Section 5.1 hereof; or
(g) The occurrence of an "event of default" under the Indenture.
The foregoing provisions of Section 6.1(c) are subject to the following
limitations: If by reason of Force Majeure the Company is unable in whole or in
part to carry out its agreements on its part herein contained, other than the
obligations on the part of the Company contained in Article IV and Sections 5.3
and 6.4 hereof, the Company shall not be deemed in default during the
continuance of such inability. The Company agrees, however, to remedy with all
reasonable dispatch the cause or causes preventing the Company from carrying out
its agreements; provided that the settlement of strikes, lockouts and other
industrial disturbances shall be entirely within the discretion of the Company
and the Company shall not be required to make settlement of strikes, lockouts
and other industrial disturbances by acceding to the demands of the opposing
party or parties when such course is in the sole judgment of the Company
unfavorable to the Company.
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SECTION 6.2. REMEDIES ON DEFAULT. Whenever any event of default referred to
in Section 6.1 hereof shall have happened and be continuing, the Trustee, as
assignee of the Issuer:
(a) shall, by notice in writing to the Company, declare the unpaid
indebtedness under Section 4.2(a) hereof to be due and payable immediately,
if concurrently with or prior to such notice the unpaid principal amount of
the Bonds shall have been declared to be due and payable, and upon any such
declaration the same (being an amount sufficient, together with other
moneys available therefor in the Bond Fund, to pay the unpaid principal of,
premium, if any, and interest accrued on, the Bonds) shall become and shall
be immediately due and payable as liquidated damages; and
(b) may take whatever action at law or in equity as may appear
necessary or desirable to collect the payments and other amounts then due
and thereafter to become due hereunder or to enforce performance and
observance of any obligation, agreement or covenant of the Company under
this Agreement.
Any amounts collected pursuant to action taken under this Section 6.2 shall
be paid into the Bond Fund (unless otherwise provided in this Agreement) and
applied in accordance with the provisions of the Indenture. No action taken
pursuant to this Section 6.2 shall relieve the Company from the Company's
obligations pursuant to Section 4.2 hereof.
No recourse shall be had for any claim based on this Agreement against any
officer, director or stockholder, past, present or future, of the Company as
such, either directly or through the Company, under any constitutional
provision, statute or rule of law, or by the enforcement of any assessment or by
any legal or equitable proceeding or otherwise.
Nothing herein contained shall be construed to prevent the Issuer from
enforcing directly any of its rights under Sections 4.2(e), 4.2(g), 5.3 and 6.4
hereof.
The Company shall promptly notify the Issuer of any action taken by the
Company under the grant of authority from the Issuer under the last paragraph of
Section 9.01 of the Indenture.
SECTION 6.3. NO REMEDY EXCLUSIVE. No remedy herein conferred upon or
reserved to the Issuer is intended to be exclusive of any other available remedy
or remedies, but each and every such remedy shall be cumulative and shall be in
addition to every other remedy given under this Agreement or now or hereafter
existing at law or in equity or by statute. No delay or omission to exercise any
right or power accruing upon any default shall impair any such right or power or
shall be construed to be a waiver thereof, but any such right and power may be
exercised from time to time and as often as may be deemed expedient. In order to
entitle the Issuer or the Trustee to exercise any remedy reserved to it in this
Article, it shall not be necessary to give any notice, other than such notice as
may be herein expressly required. Subject to the provisions of the Indenture and
hereof, such rights and remedies as are given the Issuer hereunder shall also
extend to the Trustee. The Owners of the Bonds, subject to the provisions of the
Indenture, shall be entitled to the benefit of all covenants and agreements
herein contained.
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SECTION 6.4. AGREEMENT TO PAY FEES AND EXPENSES OF COUNSEL. In the event
the Company should default under any of the provisions of this Agreement and the
Issuer or the Trustee should employ Counsel or incur other expenses for the
collection of the indebtedness hereunder or the enforcement of performance or
observance of any obligation or agreement on the part of the Company herein
contained, the Company agrees that it will on written demand therefor pay to the
Trustee or the Issuer (or to the Counsel for either of such parties if directed
by such party), the reasonable fees and expenses of such Counsel and such other
expenses so incurred by or on behalf of the Issuer or the Trustee.
SECTION 6.5. NO ADDITIONAL WAIVER IMPLIED BY ONE WAIVER; CONSENTS TO
WAIVERS. In the event any agreement contained in this Agreement should be
breached by either party and thereafter waived by the other party, such waiver
shall be limited to the particular breach so waived and shall not be deemed to
waive any other breach hereunder. No waiver shall be effective unless in writing
and signed by the party making the waiver. The Issuer shall have no power to
waive any default hereunder by the Company without the consent of the Trustee to
such waiver. The Trustee shall have the power to waive any default by the
Company hereunder, except a default under Section 3.4, 4.2(e), 4.2(g), 5.3 or
6.4 hereof, in so far as it pertains to the Issuer, without the prior written
concurrence of the Issuer. Notwithstanding the foregoing, if, after the
acceleration of the maturity of the outstanding Bonds by the Trustee pursuant to
Section 9.02 of the Indenture, (i) all arrears of principal of and interest on
the outstanding Bonds and interest on overdue principal and (to the extent
permitted by law) on overdue installments of interest at the rate of interest
borne by the Bonds on the date on which such principal or interest became due
and payable and the premium, if any, on all Bonds then Outstanding which have
become due and payable otherwise than by acceleration, and all other sums
payable under the Indenture, except the principal of and the interest on such
Bonds which by such acceleration shall have become due and payable, shall have
been paid, (ii) all other things shall have been performed in respect of which
there was a default, (iii) there shall have been paid the reasonable fees and
expenses of the Trustee and of the Owners of such Bonds, including reasonable
attorneys' fees paid or incurred and (iv) such event of default under the
Indenture shall be waived in accordance with Section 9.09 of the Indenture with
the consequence that such acceleration under Section 9.02 of the Indenture is
rescinded, then the Company's default hereunder shall be deemed to have been
waived and its consequences rescinded and no further action or consent by the
Trustee or the Issuer shall be required; provided that there has been furnished
an opinion of Bond Counsel to the effect that such waiver will not adversely
affect the exemption from federal income taxes of interest on the Bonds.
ARTICLE VII
OPTIONS AND OBLIGATIONS OF COMPANY;
PREPAYMENTS; REDEMPTION OF BONDS
SECTION 7.1. OPTION TO PREPAY. The Company shall have, and is hereby
granted, the option to prepay the payments due hereunder in whole or in part at
any time or from time to time (a) to provide for the redemption of Bonds
pursuant to the provisions of Section 3.01(A) of the Indenture or (b) to
provide for the defeasance of the Bonds pursuant to Article VIII of the
Indenture. In the event the Company elects to provide for the redemption of
Bonds as permitted
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by this Section, the Company shall notify and instruct the Trustee in accordance
with Section 7.3 hereof to redeem all or any portion of the Bonds in advance of
maturity. If the Company so elects, any redemption of Bonds pursuant to Section
3.01(A) of the Indenture may be made conditional.
SECTION 7.2. OBLIGATION TO PREPAY. The Company covenants and agrees that if
all or any part of the Bonds are unconditionally called for redemption in
accordance with the Indenture or become subject to mandatory redemption (except
as otherwise provided in Section 3.02 of the Indenture), it will prepay the
indebtedness hereunder in whole or in part in an amount sufficient to redeem
such Bonds on the date fixed for the redemption of such Bonds.
SECTION 7.3. NOTICE OF PREPAYMENT. Upon the exercise of the option granted
to the Company in Section 7.1 hereof, or upon the Company having knowledge of
the occurrence of any event requiring mandatory redemption of the Bonds in
accordance with Section 3.01(B) of the Indenture, the Company shall give written
notice to the Issuer, the Remarketing Agent, the Auction Agent and the Trustee.
The notice shall provide for the date of the application of the prepayment made
by the Company hereunder to the retirement of the Bonds in whole or in part
pursuant to call for redemption and shall be given by the Company not less than
five Business Days prior to the date notice of such redemption must be given by
the Trustee to the Bondholders as provided in Section 3.02 of the Indenture or
such later date as is acceptable to the Trustee and the Issuer.
ARTICLE VIII
MISCELLANEOUS
SECTION 8.1. NOTICES. (a) Except as otherwise provided herein, all notices,
certificates or other communications hereunder shall be sufficiently given if in
writing and shall be deemed given when mailed by first class mail, postage
prepaid, or by qualified overnight courier service, courier charges prepaid, or
by facsimile (receipt of which is orally confirmed) addressed as follows: if to
the Issuer, at 50 West Fifth Street, Room 203, Winnemucca Nevada 89445, or to
telecopy number (775) 623-6449, Attention: Comptroller; if to the Company, at
6100 Neil Road, Reno, Nevada 89520, or to telecopy number (702) 227-2250,
Attention: Treasurer; if to the Trustee, at 385 Rifle Camp Road, West Paterson,
New Jersey 07424, or to telecopy number (973) 357-7840, Attention: Corporate
Trust Services; if to the Remarketing Agent, at the address set forth in the
Remarketing Agreement, if any; and if to the Auction Agent, at the address set
forth in the Auction Agreement, if any. In case by reason of the suspension of
regular mail service, it shall be impracticable to give notice by first class
mail of any event to the Issuer, to the Company, to the Remarketing Agent, to
the Auction Agent when such notice is required to be given pursuant to any
provisions of this Agreement, then any manner of giving such notice as shall be
satisfactory to the Trustee shall be deemed to be sufficient giving of such
notice. The Issuer, the Company, the Trustee, the Remarketing Agent and the
Auction Agent may, by notice pursuant to this Section 8.1, designate any
different addresses to which subsequent notices, certificates or other
communications shall be sent.
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(b) The Trustee agrees to accept and act upon instructions or
directions pursuant to this Agreement sent by unsecured e-mail, facsimile
transmission or other similar unsecured electronic methods, provided,
however, that (a) the Company and/or Issuer, subsequent to such
transmission of written instructions, shall, upon request by the Trustee,
provide the originally executed instructions or directions to the Trustee,
(b) upon request by the Trustee, such originally executed instructions or
directions shall be signed by a person as may be designated and authorized
to sign for the Company and/or Issuer or in the name of the Company and/or
Issuer, by an authorized representative of the Company and/or Issuer, and
(c) upon the request by the Trustee, the Company and/or Issuer shall
provide to the Trustee an incumbency certificate listing such designated
persons, which incumbency certificate shall be amended whenever a person is
to be added or deleted from the listing. If the Company and/or Issuer
elects to give the Trustee e-mail or facsimile instructions (or
instructions by a similar electronic method) and the Trustee elects to act
upon such instructions, the Trustee's reasonable interpretation and
understanding of such instructions shall be deemed controlling. The Trustee
shall not be liable for any losses, costs or expenses arising directly or
indirectly from the Trustee's reasonable reliance upon and compliance with
such instructions notwithstanding that such instructions conflict or are
inconsistent with a subsequent written instruction.
SECTION 8.2. ASSIGNMENTS. This Agreement may not be assigned by either
party without consent of the other and the Trustee, except that the Issuer shall
assign to the Trustee its rights under this Agreement (except under Sections
4.2(e), 4.2(g), 5.3, and 6.4 hereof) as provided by Section 4.4 hereof, and the
Company may assign its rights under this Agreement to any transferee or any
surviving or resulting corporation as provided by Section 5.1 hereof.
SECTION 8.3. SEVERABILITY. If any provision of this Agreement shall be held
or deemed to be or shall, in fact, be illegal, inoperative or unenforceable, the
same shall not affect any other provision or provisions herein contained or
render the same invalid, inoperative, or unenforceable to any extent whatever.
SECTION 8.4. EXECUTION OF COUNTERPARTS. This Agreement may be
simultaneously executed in several counterparts, each of which shall be an
original and all of which shall constitute but one and the same instrument.
SECTION 8.5. AMOUNTS REMAINING IN BOND FUND. It is agreed by the parties
hereto that after payment in full of (i) the Bonds (or provision for payment
thereof having been made in accordance with the provisions of the Indenture),
(ii) the fees, charges and expenses of the Trustee in accordance with the
Indenture, (iii) the Administrative Expenses, (iv) the fees and expenses of the
Remarketing Agent, the Auction Agent and the Issuer and (v) all other amounts
required to be paid under this Agreement and the Indenture, any amounts
remaining in the Bond Fund shall belong to and be paid to the Company by the
Trustee.
SECTION 8.6. AMENDMENTS, CHANGES AND MODIFICATIONS. This Agreement may be
amended, changed, modified, altered or terminated only by written instrument
executed by the Issuer and the Company, and only if the written consent of the
Trustee thereto is obtained, and only in accordance with the provisions of
Article XII of the Indenture.
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SECTION 8.7. GOVERNING LAW. This Agreement shall be governed exclusively by
and construed in accordance with the applicable laws of the State.
SECTION 8.8. AUTHORIZED ISSUER AND COMPANY REPRESENTATIVES. Whenever under
the provisions of this Agreement the approval of the Issuer or the Company is
required to take some action at the request of the other, such approval of such
request shall be given for the Issuer by the Authorized Issuer Representative
and for the Company by the Authorized Company Representative, and the other
party hereto and the Trustee shall be authorized to act on any such approval or
request and neither party hereto shall have any complaint against the other or
against the Trustee as a result of any such action taken.
SECTION 8.9. TERM OF THE AGREEMENT. This Agreement shall be in full force
and effect from its date to and including such date as all of the Bonds issued
under the Indenture shall have been fully paid or retired (or provision for such
payment shall have been made as provided in the Indenture), provided that all
representations and certifications by the Company as to all matters affecting
the tax-exempt status of the Bonds and the covenants of the Company in Sections
4.2(c), 4.2(d), 4.2(e), 4.2(f) and 4.2(g) hereof shall survive the termination
of this Agreement.
SECTION 8.10. CANCELLATION AT EXPIRATION OF TERM. At the acceleration,
termination or expiration of the term of this Agreement and following full
payment of the Bonds or provision for payment thereof and of all other fees and
charges having been made in accordance with the provisions of this Agreement and
the Indenture, the Issuer shall deliver to the Company any documents and take or
cause the Trustee to take such actions as may be necessary to effectuate the
cancellation and evidence the termination of this Agreement.
SECTION 8.11. BOND INSURANCE. The payment of the principal of and interest
on the Bonds when due is to be insured under, and to the extent provided in, the
Bond Insurance Policy, including the endorsements thereto, to be issued by the
Bond Insurer, and the Issuer and the Company agree to be bound by the provisions
contained in Appendix C to the Indenture and the Company agrees to be bound by
the provisions contained in the Insurance Agreement. In the event of any
conflict between the provisions of Appendix C to the Indenture and the
provisions of this Agreement, the provisions of Appendix C shall govern and
control.
All references in this Agreement to the Bond Insurer shall only apply so
long as a Bond Insurance Policy issued by the Bond Insurer is in effect for any
of the Bonds (and the Bond Insurer has not failed to comply with its payment
obligations under the Bond Insurance Policy).
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IN WITNESS WHEREOF, the Issuer and the Company have caused this Agreement
to be executed in their respective corporate names and their respective
corporate seals to be hereunto affixed and attested by their duly authorized
officers, all as of the date first above written.
HUMBOLDT COUNTY, NEVADA
By
Chairman
Board of County Commissioners
(SEAL)
Attest:
County Clerk
SIERRA PACIFIC POWER COMPANY
By
Treasurer
(SEAL)
Attest:
Secretary
IN WITNESS WHEREOF, the Issuer and the Company have caused this Agreement
to be executed in their respective corporate names and their respective
corporate seals to be hereunto affixed and attested by their duly authorized
officers, all as of the date first above written.
HUMBOLDT COUNTY, NEVADA
By
Chairman
Board of County Commissioners
(SEAL)
Attest:
County Clerk
SIERRA PACIFIC POWER COMPANY
By
Vice President, Finance and Risk,
and Treasurer
(SEAL)
Attest:
Secretary
Exhibit 10(C)
FINANCING AGREEMENT
Dated as of November 1, 2006
By and Between
WASHOE COUNTY, NEVADA
and
SIERRA PACIFIC POWER COMPANY
RELATING TO
GAS FACILITIES REFUNDING REVENUE BONDS
(SIERRA PACIFIC POWER COMPANY PROJECT)
SERIES 2006A
The amounts payable to the Issuer (except for amounts payable to, and
certain rights and privileges of, the Issuer under Sections 4.2(e), 4.2(g), 5.3
and 6.4 hereof and any rights of the Issuer to receive any notices,
certificates, requests, requisitions or communications hereunder) and certain
other rights of the Issuer under this Financing Agreement have been pledged and
assigned under the Indenture of Trust dated as of November 1, 2006, between the
Issuer and The Bank of New York, as Trustee.
FINANCING AGREEMENT
TABLE OF CONTENTS
(This Table of Contents is not a part of this Agreement and
is only for convenience of reference).
SECTION HEADING PAGE
------- ------- ----
ARTICLE I DEFINITIONS........................................... 1
ARTICLE II REPRESENTATIONS....................................... 5
Section 2.1. Representations and Covenants by the Issuer........... 5
Section 2.2. Representations by the Company........................ 6
ARTICLE III ISSUANCE OF THE BONDS................................. 7
Section 3.1. Agreement to Issue Bonds; Application of Bond
Proceeds........................................... 7
Section 3.2. Deposit of Additional Funds by Company; Redemption of
Prior Bonds........................................ 7
Section 3.3. Investment of Moneys in the Bond Fund and the Prior
Bonds Redemption Fund.............................. 7
Section 3.4. Tax Exempt Status of Bonds............................ 8
ARTICLE IV LOAN AND PROVISIONS FOR REPAYMENT..................... 8
Section 4.1. Loan of Bond Proceeds................................. 8
Section 4.2. Loan Repayments and Other Amounts Payable............. 9
Section 4.3. No Defense or Set-Off................................. 11
Section 4.4. Payments Pledged and Assigned......................... 11
Section 4.5. Payment of the Bonds and Other Amounts................ 11
ARTICLE V SPECIAL COVENANTS AND AGREEMENTS...................... 12
Section 5.1. Company to Maintain its Corporate Existence;
Conditions Under Which Exceptions Permitted........ 12
Section 5.2. Annual Statement...................................... 12
Section 5.3. Maintenance and Repair; Insurance; Taxes;
Disposition........................................ 13
Section 5.4. Recordation and Other Instruments..................... 13
Section 5.5. No Warranty by the Issuer............................. 13
Section 5.6. Agreement as to Ownership of the Project.............. 14
Section 5.7. Company to Furnish Notice of Rate Period Adjustments;
Liquidity Facility Requirements; Auction Rate
Period Provisions.................................. 14
Section 5.8. Information Reporting, Etc............................ 14
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Section 5.9. Limited Liability of Issuer........................... 15
Section 5.10. Inspection of Project................................. 15
Section 5.11. Indenture Covenants................................... 15
ARTICLE VI EVENTS OF DEFAULT AND REMEDIES........................ 15
Section 6.1. Events of Default Defined............................. 15
Section 6.2. Remedies on Default................................... 17
Section 6.3. No Remedy Exclusive................................... 18
Section 6.4. Agreement to Pay Fees and Expenses of Counsel......... 18
Section 6.5. No Additional Waiver Implied by One Waiver; Consents
to Waivers......................................... 18
ARTICLE VII OPTIONS AND OBLIGATIONS OF COMPANY; PREPAYMENTS;
REDEMPTION OF BONDS................................ 19
Section 7.1. Option to Prepay...................................... 19
Section 7.2. Obligation to Prepay.................................. 19
Section 7.3. Notice of Prepayment.................................. 19
ARTICLE VIII MISCELLANEOUS......................................... 19
Section 8.1. Notices............................................... 19
Section 8.2. Assignments........................................... 20
Section 8.3. Severability.......................................... 20
Section 8.4. Execution of Counterparts............................. 21
Section 8.5. Amounts Remaining in Bond Fund........................ 21
Section 8.6. Amendments, Changes and Modifications................. 21
Section 8.7. Governing Law......................................... 21
Section 8.8. Authorized Issuer and Company Representatives......... 21
Section 8.9. Term of the Agreement................................. 21
Section 8.10. Cancellation at Expiration of Term.................... 21
Section 8.11. Bond Insurance........................................ 21
Signature................................................................ 23
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THIS FINANCING AGREEMENT made and entered into as of November 1, 2006, by
and between WASHOE COUNTY, NEVADA, a political subdivision of the State of
Nevada, party of the first part (hereinafter referred to as the "Issuer"), and
SIERRA PACIFIC POWER COMPANY, a corporation duly organized and existing under
the laws of the State of Nevada, party of the second part (hereinafter referred
to as the "Company"),
WITNESSETH:
In consideration of the respective representations and agreements
hereinafter contained, the parties hereto agree as follows (provided, that in
the performance of the agreements of the Issuer herein contained, any obligation
it may thereby incur shall not constitute or give rise to a pecuniary liability
or a charge upon its general credit or against its taxing powers but shall be
payable solely out of the Revenues (as hereinafter defined) derived from this
Financing Agreement and the Bonds, as hereinafter defined):
ARTICLE I
DEFINITIONS
The following terms shall have the meanings specified in this Article
unless the context clearly requires otherwise. The singular shall include the
plural and the masculine shall include the feminine.
"Act" means the County Economic Development Revenue Bond Law, as amended,
contained in Sections 244A.669 to 244A.763, inclusive, of the Nevada Revised
Statutes.
"Administrative Expenses" means the reasonable and necessary expenses
(including the reasonable value of employee services and fees of Counsel)
incurred by the Issuer in connection with the Bonds, this Agreement, the
Indenture and any transaction or event contemplated by this Agreement or the
Indenture.
"Agreement" means this Financing Agreement by and between the Issuer and
the Company, as from time to time amended and supplemented.
"Auction Agent" means the auction agent appointed in accordance with the
provisions of the Indenture.
"Authorized Company Representative" means any person who, at the time,
shall have been designated to act on behalf of the Company by a written
certificate furnished to the Issuer, the Remarketing Agent and the Trustee
containing the specimen signature of such person and signed on behalf of the
Company by any officer of the Company. Such certificate may designate an
alternate or alternates.
"Authorized Issuer Representative" means any person at the time designated
to act on behalf of the Issuer by a written certificate furnished to the Company
and the Trustee containing the specimen signature of such person and signed on
behalf of the Issuer by its Chairman. Such certificate may designate an
alternate or alternates.
"Bankruptcy Code" means the United States Bankruptcy Reform Act of 1978, as
amended from time to time, or any substitute or replacement legislation.
"Bond" or "Bonds" means the Issuer's bonds identified in Section 2.02 of
the Indenture.
"Bond Counsel" means the Counsel who renders the opinion as to the
tax-exempt status of interest on the Bonds or other nationally recognized
municipal bond counsel mutually acceptable to the Issuer and the Company.
"Bond Fund" means the fund created by Section 6.02 of the Indenture.
"Code" means the United States Internal Revenue Code of 1986, as amended,
and regulations promulgated or proposed thereunder.
"Company" means Sierra Pacific Power Company, a Nevada corporation, and its
successors and assigns and any surviving, resulting or transferee corporation as
permitted in Section 5.1 hereof.
"Counsel" means an attorney at law or a firm of attorneys (who may be an
employee of or counsel to the Issuer or the Company or the Trustee) duly
admitted to the practice of law before the highest court of any state of the
United States of America or of the District of Columbia.
"Delivery Agreement" means the Delivery Agreement dated the Dated Date,
between the Company and the Trustee, as amended, supplemented or restated from
time to time, pursuant to which the Company will issue to the Trustee the G&R
Notes at the time of the initial authentication and delivery of the Bonds.
"Escrow Agreement" means the Escrow Agreement dated as of the Dated Date
between the Company and the Series 1987 Trustee.
"Extraordinary Services" and "Extraordinary Expenses" means all services
rendered and all expenses (including fees and expenses of Counsel) incurred
under the Indenture and the Tax Agreement other than Ordinary Services and
Ordinary Expenses.
"Force Majeure" means acts of God, strikes, lockouts or other industrial
disturbances; acts of public enemies; orders or restraints of any kind of the
governments of the United States or of the State, or any of their departments,
agencies or officials, or any civil or military authority; insurrections; riots;
landslides; lightning; earthquakes; fires; tornadoes; volcanoes; storms;
droughts; floods; explosions, breakage, or malfunction or accident to machinery,
transmission
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lines, pipes or canals, even if resulting from negligence; civil disturbances;
or any other cause not reasonably within the control of the Company.
"G&R Indenture" means the General and Refunding Mortgage Indenture dated as
of May 1, 2001 between the Company and the G&R Trustee, as amended and
supplemented.
"G&R Notes" means the Company's $58,700,000 General and Refunding Mortgage
Note, Series N, No. 2, due August 1, 2031.
"G&R Trustee" means The Bank of New York, as trustee under the G&R
Indenture or any successor trustee.
"Governing Body" means the Board of County Commissioners of the Issuer.
"Hereof," "herein," "hereunder" and other words of similar import refer to
this Agreement as a whole.
"Indenture" means the Indenture of Trust relating to this Agreement between
the Issuer and The Bank of New York, as Trustee, of even date herewith, pursuant
to which the Bonds are authorized to be issued, including any indentures
supplemental thereto or amendatory thereof.
"Issuer" means Washoe County, Nevada, and any successor body to the duties
or functions of the Issuer.
"Ordinary Services" and "Ordinary Expenses" means those services normally
rendered and those expenses including fees and expenses of Counsel, normally
incurred by a trustee or paying agent under instruments similar to the Indenture
and the Tax Agreement.
"Owner" or "owner of Bonds" means the Person or Persons in whose name or
names a Bond shall be registered on books of the Issuer kept by the Registrar
for that purpose in accordance with the terms of the Indenture.
"Person" means natural persons, firms, partnerships, associations,
corporations, trusts and public bodies.
"Prior Bonds" means the Series 1987 Bonds, the Series 1990 Bonds and the
Series 1992 Bonds.
"Prior Bond Funds" means the Series 1990 Bond Fund and the Series 1992 Bond
Fund.
"Prior Indentures" means the Series 1987 Indenture, the Series 1990
Indenture and the Series 1992 Indenture.
"Prior Trustees" means the Series 1987 Trustee, the Series 1990 Trustee and
the Series 1992 Trustee.
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"Project" means the Project as defined in the Project Certificate.
"Project Certificate" means the Company's Project and Refunding
Certificate, delivered concurrently with the issuance of the Bonds, with respect
to certain facts which are within the knowledge of the Company and certain
reasonable assumptions of the Company, to enable Chapman and Cutler LLP, as Bond
Counsel, to determine that interest on the Bonds is not includable in the gross
income of the Owners of the Bonds for federal income tax purposes.
"Rebate Fund" means the Rebate Fund, if any, created and established
pursuant to the Tax Agreement.
"Regulated Utility Company" means a corporation (or a limited liability
company) engaged in the distribution of electricity, gas and/or water and which
is regulated by the applicable public service commissions in all of the states
that comprise its service area.
"Remarketing Agent" means the remarketing agent, if any, appointed in
accordance with Section 4.08 of the Indenture and any permitted successor
thereto.
"Reorganization" means any reorganization, consolidation or merger of the
Company or its affiliates, or any transfer or lease of a substantial portion of
the assets of the Company or its affiliates, as a result of which the obligor
under the Agreement or the obligor on the G&R Notes ceases to be a Regulated
Utility Company.
"Series 1987 Bonds" means the Issuer's Variable Rate Demand Gas Facilities
Revenue Bonds (Sierra Pacific Power Company Project) Series 1987, currently
outstanding in the aggregate principal amount of $17,500,000.
"Series 1987 Indenture" means the Indenture of Trust dated December 1, 1987
between the Issuer and the Series 1987 Trustee, as trustee, pursuant to which
the Series 1987 Bonds were issued.
"Series 1987 Trustee" means The Bank of New York, as current trustee under
the Series 1987 Indenture.
"Series 1990 Bond Fund" means the fund established pursuant to Section 6.02
of the Series 1990 Indenture.
"Series 1990 Bonds" means the Issuer's Gas Facilities Revenue Bonds (Sierra
Pacific Power Company Project) Series 1990, currently outstanding in the
aggregate principal amount of $20,000,000.
"Series 1990 Indenture" means the Indenture of Trust dated September 1,
1990 between the Issuer and the Series 1990 Trustee, as trustee, pursuant to
which the Series 1990 Bonds were issued.
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"Series 1990 Trustee" means The Bank of New York, as current trustee under
the Series 1990 Indenture.
"Series 1992 Bond Fund" means the fund established pursuant to Section 5.02
of the Series 1992 Indenture.
"Series 1992 Bonds" means the Issuer's Gas Facilities Revenue Bonds (Sierra
Pacific Power Company Project) Series 1992, currently outstanding in the
aggregate principal amount of $21,200,000.
"Series 1992 Indenture" means the Indenture of Trust dated November 1, 1992
between the Issuer and the Series 1992 Trustee, as trustee, pursuant to which
the Series 1992 Bonds were issued.
"Series 1992 Trustee" means The Bank of New York, as current trustee under
the Series 1992 Indenture.
"State" means the State of Nevada.
"Tax Agreement" means the Tax Exemption Certificate and Agreement with
respect to the Bonds, dated the date of delivery of the Bonds, among the
Company, the Issuer and the Trustee, as from time to time amended and
supplemented.
"Trust Estate" means the property conveyed to the Trustee pursuant to the
Granting Clauses of the Indenture.
"Trustee" means The Bank of New York, as Trustee under the Indenture, and
any successor Trustee appointed pursuant to Section 10.06 or 10.09 of the
Indenture at the time serving as Trustee thereunder, and any separate or
co-trustee serving as such thereunder.
All other terms used herein which are defined in the Indenture shall have
the same meanings assigned them in the Indenture unless the context otherwise
requires.
ARTICLE II
REPRESENTATIONS
SECTION 2.1. REPRESENTATIONS AND COVENANTS BY THE ISSUER. The Issuer makes
the following representations and covenants as the basis for the undertakings on
its part herein contained:
(a) The Issuer is a duly organized and existing political subdivision
of the State of Nevada. Under the provisions of the Act, the Issuer is
authorized to enter into the transactions contemplated by this Agreement,
the Indenture and the Tax Agreement and to carry out its obligations
hereunder and thereunder. The Issuer has duly authorized the execution and
delivery of this Agreement, the Indenture and the Tax Agreement.
-5-
(b) The Bonds are to be issued under and secured by the Indenture,
pursuant to which certain of the Issuer's interests in this Agreement and
the Revenues derived by the Issuer pursuant to this Agreement will be
pledged and assigned as security for payment of the principal of, premium,
if any, and interest on, the Bonds.
(c) The Governing Body of the Issuer has found that the issuance of
the Bonds will further the public purposes of the Act.
(d) The Issuer has not assigned and will not assign any of its
interests in this Agreement other than pursuant to the Indenture.
(e) No member of the Governing Body of the Issuer, nor any other
officer of the Issuer, has any interest, financial (other than ownership of
less than one-tenth of one percent (.1%) of the publicly traded securities
issued by the Company or its affiliated corporations), employment or other,
in the Company or in the transactions contemplated hereby.
SECTION 2.2. REPRESENTATIONS BY THE COMPANY. The Company makes the
following representations as the basis for the undertakings on its part herein
contained:
(a) The Company is a corporation duly incorporated under the laws of
the State and is in good standing in the State, is qualified to do business
as a foreign corporation in all other states and jurisdictions wherein the
nature of the business transacted by the Company or the nature of the
property owned or leased by it makes such licensing or qualification
necessary, and has the power to enter into and by proper corporate action
has been duly authorized to execute and deliver this Agreement and the Tax
Agreement.
(b) Neither the execution and delivery of this Agreement or the Tax
Agreement, the consummation of the transactions contemplated hereby and
thereby, nor the fulfillment of or compliance with the terms and conditions
of this Agreement and the Tax Agreement, conflicts with or results in a
breach of any of the terms, conditions or provisions of any corporate
restriction or any agreement or instrument to which the Company is now a
party or by which it is bound, or constitutes a default under any of the
foregoing, or results in the creation or imposition of any lien, charge or
encumbrance whatsoever upon any of the property or assets of the Company
under the terms of any instrument or agreement other than the Indenture.
(c) The statements, information and descriptions contained in the
Project Certificate and the Tax Agreement, as of the date hereof and at the
time of the delivery of the Bonds to the Underwriter, are and will be true,
correct and complete, do not and will not contain any untrue statement or
misleading statement of a material fact, and do not and will not omit to
state a material fact required to be stated therein or necessary to make
the statements, information and descriptions contained therein, in the
light of the circumstances under which they were made, not misleading.
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ARTICLE III
ISSUANCE OF THE BONDS
SECTION 3.1. AGREEMENT TO ISSUE BONDS; APPLICATION OF BOND PROCEEDS. In
order to provide funds to lend to the Company to refund the Prior Bonds as
provided in Section 4.1 hereof, the Issuer agrees that it will issue under the
Indenture, sell and cause to be delivered to the Underwriter, its Bonds in the
aggregate principal amount of $58,700,000, bearing interest and maturing as set
forth in the Indenture. The Issuer will thereupon deposit the proceeds received
from the sale of the Bonds as follows: (1) in the Bond Fund, a sum equal to the
accrued interest, if any, paid by the Underwriter; (2) $41,200,000 in the Prior
Bonds Redemption Fund to be remitted by the Trustee to the Series 1990 Trustee
and the Series 1992 Trustee for deposit in the Prior Bond Funds to be used to
pay to the owners thereof the principal of the Series 1990 Bonds and the Series
1992 Bonds upon redemption thereof; and (3) $17,500,000 with the Series 1987
Trustee under the Escrow Agreement to be used as provided therein.
SECTION 3.2. DEPOSIT OF ADDITIONAL FUNDS BY COMPANY; REDEMPTION OF PRIOR
BONDS. The Company covenants that such additional amounts as may be required to
redeem the Prior Bonds in accordance with Section 3.1 hereof will be timely
deposited with the Prior Trustee pursuant to the Prior Indentures for such
purpose. Income derived from the investment of the proceeds of the Bonds
deposited in the two accounts of the Prior Bonds Redemption Fund will be used,
to the extent available, to satisfy the obligations of the Company specified in
this Section 3.2. The Company covenants that it will cause the Prior Bonds to be
redeemed within 90 days after the issuance and delivery of the Bonds.
SECTION 3.3. INVESTMENT OF MONEYS IN THE BOND FUND AND THE PRIOR BONDS
REDEMPTION FUND. Except as otherwise herein provided, any moneys held as a part
of the Bond Fund and the Prior Bonds Redemption Fund shall be invested or
reinvested by the Trustee at the specific written direction of an Authorized
Company Representative as to specific investments, to the extent permitted by
law, in:
(a) bonds or other obligations of the United States of America;
(b) bonds or other obligations, the payment of the principal of and
interest on which is unconditionally guaranteed by the United States of
America;
(c) obligations issued or guaranteed as to principal and interest by
any agency or person controlled or supervised by and acting as an
instrumentality of the United States of America pursuant to authority
granted by the Congress of the United States of America;
(d) obligations issued or guaranteed by any state of the United States
of America, or any political subdivision of any such state, or in funds
consisting of such obligations to the extent described in Section
1.148-8(e)(3)(iii) of the 1992 Treasury Regulations;
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(e) prime commercial paper;
(f) prime finance company paper;
(g) bankers' acceptances drawn on and accepted by commercial banks;
(h) repurchase agreements fully secured by obligations issued or
guaranteed as to principal and interest by the United States of America or
by any person controlled or supervised by and acting as an instrumentality
of the United States of America pursuant to authority granted by the
Congress of the United States of America;
(i) certificates of deposit issued by commercial banks, including
banks domiciled outside of the United States of America; and
(j) units of taxable government money market portfolios composed of
obligations guaranteed as to principal and interest by the United States of
America or repurchase agreements fully collateralized by such obligations.
The investments so purchased shall be held by the Trustee and shall be
deemed at all times a part of the fund and the accounts therein, if any, for
which they were made and the interest accruing thereon and any profit realized
therefrom shall be credited to such fund and the accounts therein, if any,
subject to the provisions of the Tax Agreement. The Company agrees that to the
extent any moneys in the Bond Fund represent moneys held for the payment of
particular Bonds, or to the extent that any moneys are held for the payment of
the purchase price of Bonds pursuant to Article IV of the Indenture, such moneys
shall not be invested.
SECTION 3.4. TAX EXEMPT STATUS OF BONDS. The Company covenants and agrees
that it has not taken or permitted and will not take or permit any action which
results in interest paid on the Bonds being included in gross income of the
holders or beneficial owners of the Bonds for purposes of federal income
taxation (other than a holder or beneficial owner who is a "substantial user" of
the Project or a "related person" within the meaning of Section 147(a) of the
Code). The Company covenants that none of the proceeds of the Bonds or the
payments to be made under this Agreement, or any other funds which may be deemed
to be proceeds of the Bonds pursuant to Section 148(a) of the Code, will be
invested or used in such a way, and that no actions will be taken or not taken,
as to cause the Bonds to be treated as "arbitrage bonds" within the meaning of
Section 148(a) of the Code. Without limiting the generality of the foregoing,
the Company covenants and agrees that it will comply with the provisions of the
Tax Agreement and the Project Certificate.
ARTICLE IV
LOAN AND PROVISIONS FOR REPAYMENT
SECTION 4.1. LOAN OF BOND PROCEEDS. (a) The Issuer agrees, upon the terms
and conditions in this Agreement, to lend to the Company the proceeds (exclusive
of accrued interest, if any) received by the Issuer from the sale of the Bonds
in order to refund the Prior Bonds, and
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the Company agrees to apply the gross proceeds of such loan to the refunding of
the Prior Bonds as set forth in Sections 3.1 and 3.2 hereof.
(b) The Issuer and the Company expressly reserve the right to enter
into, to the extent permitted by law, an agreement or agreements other than
this Agreement, with respect to the issuance by the Issuer, under an
indenture or indentures other than the Indenture, of obligations to provide
additional funds to refund all or any principal amount of the Bonds.
SECTION 4.2. LOAN REPAYMENTS AND OTHER AMOUNTS PAYABLE. (a) On each date
provided in or pursuant to the Indenture for the payment (whether at maturity or
upon redemption or acceleration) of principal of, and premium, if any, and
interest on, the Bonds, until the principal of, and premium, if any, and
interest on, the Bonds shall have been fully paid or provision for the payment
thereof shall have been made in accordance with the Indenture, the Company shall
pay to the Trustee in immediately available funds, for deposit in the Bond Fund,
as a repayment installment of the loan of the proceeds of the Bonds pursuant to
Section 4.1(a) hereof, a sum equal to the amount payable on such date (whether
at maturity or upon redemption or acceleration) as principal of, and premium, if
any, and interest on, the Bonds as provided in the Indenture; provided, however,
that the obligation of the Company to make any such repayment installment shall
be reduced by the amount of any moneys then on deposit in the Bond Fund and
available for such payment; and provided further, that the obligation of the
Company to make any such payment shall be deemed to be satisfied and discharged
to the extent provided for under a liquidity facility (if applicable) or under
the G&R Notes.
(b) The Company shall pay to the Trustee amounts equal to the amounts
to be paid by the Trustee for the purchase of Bonds pursuant to Article IV
of the Indenture. Such amounts shall be paid by the Company to the Trustee
in immediately available funds on the date such payments pursuant to
Section 4.05 of the Indenture are to be made; provided, however, that the
obligation of the Company to make any such payment shall be deemed to be
satisfied and discharged to the extent moneys are available from the source
described in clause (i) of Section 4.05(a) of the Indenture and to the
extent moneys are available under any liquidity facility (if applicable).
(c) The Company agrees to pay to the Trustee (i) the fees of the
Trustee for the Ordinary Services rendered by it and an amount equal to the
Ordinary Expenses incurred by it under the Indenture and the Tax Agreement,
as and when the same become due, and (ii) the reasonable fees, charges and
expenses of the Trustee for reasonable Extraordinary Services and
Extraordinary Expenses, as and when the same become due, incurred under the
Indenture and the Tax Agreement. The Company agrees that the Trustee, its
officers, agents, servants and employees, shall not be liable for, and
agrees that it will at all times indemnify and hold harmless the Trustee,
its officers, agents, servants and employees against, and pay all expenses
of the Trustee, its officers, agents, servants and employees, relating to
any lawsuit, proceeding or claim and resulting from any action or omission
taken or made by or on behalf of the Trustee, its officers, agents,
servants and employees pursuant to this Agreement, the Indenture or the Tax
Agreement, that may be occasioned by any cause (other than the negligence
or willful misconduct of the Trustee, its officers, agents, servants and
employees). In case any action shall be brought against the Trustee in
respect of which indemnity may be sought against the
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Company, the Trustee shall promptly notify the Company in writing and the
Company shall be entitled to assume control of the defense thereof,
including the employment of Counsel reasonably satisfactory to the Trustee
and the payment of all expenses. The Trustee shall have the right to employ
separate Counsel in any such action and participate in the defense thereof,
but the fees and expenses of such Counsel shall be paid by the Trustee
unless (i) the employment of such Counsel has been authorized by the
Company, (ii) the Trustee has determined (which determination may be based
upon an opinion of counsel delivered to the Trustee and furnished to the
Company) that there may be a conflict of interest of such Counsel retained
by the Company between the Company and the Trustee in the conduct of such
defense, (iii) the Company ceases or terminates the employment of such
Counsel retained by the Company or (iv) such Counsel retained by the
Company withdraws with respect to such defense. The Company shall not be
liable for any settlement of any such action without its consent, but if
any such action is settled with the consent of the Company or if there be
final judgment for the plaintiff in any such action, the Company agrees to
indemnify and hold harmless the Trustee from and against any loss or
liability by reason of such settlement or final judgment. The Company
agrees that the indemnification provided herein shall survive the
termination of this Agreement or the Indenture or the resignation of the
Trustee. For purposes of this Section 4.2(c), the Trustee is deemed a third
party beneficiary of this Agreement.
(d) The Company agrees to pay all costs incurred in connection with
the issuance of the Bonds from sources other than Bond proceeds and the
Issuer shall have no obligation with respect to such costs.
(e) The Company agrees to indemnify and hold harmless the Issuer and
any member, officer, official or employee of the Issuer against any and all
losses, costs, charges, expenses, judgments and liabilities created by or
arising out of this Agreement, the Indenture, the Remarketing Agreement,
the Auction Agreement, the Bond Purchase Agreement, any Broker- Dealer
Agreement or the Tax Agreement or otherwise incurred in connection with the
issuance of the Bonds. The Company agrees to pay the Issuer its Closing Fee
in connection with the issuance of the Bonds in the amount of $50,000. The
Issuer may submit to the Company periodic statements, not more frequently
than monthly, for its Administrative Expenses and the Company shall make
payment to the Issuer of the full amount of each such statement within 30
days after the Company receives such statement.
(f) The Company agrees to pay (i) to the Remarketing Agent the
reasonable fees, charges and expenses of such Remarketing Agent and (ii) to
the Auction Agent the reasonable fees, charges and expenses of such Auction
Agent, and the Issuer shall have no obligation or liability with respect to
the payment of any such fees, charges or expenses.
(g) In the event the Company shall fail to make any of the payments
required by (a) or (b) of this Section 4.2, the payment so in default shall
continue as an obligation of the Company until the amount in default shall
have been fully paid and the Company will pay interest to the extent
permitted by law, on any overdue amount at the rate of interest borne by
the Bonds on the date on which such amount became due and payable until
paid. In the event that the Company shall fail to make any of the payments
required by (c), (d), (e) or (f) of this Section 4.2, the payment so in
default shall continue as an obligation of the Company until the amount in
default
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shall have been fully paid, and the Company agrees to pay the same with
interest thereon to the extent permitted by law at a rate 1% above the rate
of interest then charged by the Trustee on 90-day commercial loans to its
prime commercial borrowers until paid.
SECTION 4.3. NO DEFENSE OR SET-OFF. The obligation of the Company to make
the payments pursuant to this Agreement shall be absolute and unconditional
without defense or set-off by reason of any default by the Issuer under this
Agreement or under any other agreement between the Company and the Issuer or for
any other reason, it being the intention of the parties that the payments
required hereunder will be paid in full when due without any delay or diminution
whatsoever.
SECTION 4.4. PAYMENTS PLEDGED AND ASSIGNED. It is understood and agreed
that all payments required to be made by the Company pursuant to Section 4.2
hereof (except payments made to the Trustee pursuant to Section 4.2(c) hereof,
to the Remarketing Agent and the Auction Agent pursuant to Section 4.2(f)
hereof, to the Issuer pursuant to Section 4.2(e) hereof and to any or all the
Issuer and the Trustee and the Remarketing Agent pursuant to Section 4.2(g)
hereof) and certain rights of the Issuer hereunder are pledged and assigned by
the Indenture. The Company consents to such pledge and assignment. The Issuer
hereby directs the Company and the Company hereby agrees to pay or cause to be
paid to the Trustee all said amounts except payments to be made to the
Remarketing Agent and the Auction Agent pursuant to Section 4.2(f) hereof and
payments to be made to the Issuer pursuant to Sections 4.2(e) and (g) hereof.
The Project will not constitute any part of the security for the Bonds, except
to the extent that the Trustee as holder of G&R Notes has a lien on property
under the G&R Indenture.
SECTION 4.5. PAYMENT OF THE BONDS AND OTHER AMOUNTS. The Bonds and interest
and premium, if any, thereon shall be payable solely from (i) payments made by
the Company to the Trustee under Section 4.2(a) hereof and (ii) other moneys on
deposit in the Bond Fund and available therefor.
Payments of principal of, and premium, if any, or interest on, the Bonds
with moneys in the Bond Fund constituting proceeds from the sale of the Bonds or
earnings on investments made under the provisions of the Indenture shall be
credited against the obligation to pay required by Section 4.2(a) hereof.
Whenever any Bonds are redeemable in whole or in part at the option of the
Company, the Trustee, on behalf of the Issuer, shall redeem the same upon the
request of the Company and such redemption (unless conditional) shall be made
from payments made by the Company to the Trustee under Section 4.2(a) hereof
equal to the redemption price of such Bonds.
Whenever payment or provision therefor has been made in respect of the
principal of, or premium, if any, or interest on, all or any portion of the
Bonds in accordance with the Indenture (whether at maturity or upon redemption
or acceleration or upon provision for payment in accordance with Article VIII of
the Indenture), payments shall be deemed paid to the extent such payment or
provision therefor has been made and is considered to be a payment of principal
of, or premium, if any, or interest on, such Bonds. If such Bonds are thereby
deemed paid in full, the Trustee shall notify the Company and the Issuer that
such payment requirement has been
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satisfied. Subject to the foregoing, or unless the Company is entitled to a
credit under this Agreement or the Indenture, all payments shall be in the full
amount required by Section 4.2(a) hereof.
ARTICLE V
SPECIAL COVENANTS AND AGREEMENTS
SECTION 5.1. COMPANY TO MAINTAIN ITS CORPORATE EXISTENCE; CONDITIONS UNDER
WHICH EXCEPTIONS PERMITTED. The Company agrees that during the term of this
Agreement, it will maintain its corporate existence and its good standing in the
State, will not dissolve or otherwise dispose of all or substantially all of its
assets and will not consolidate with or merge into another corporation unless
the acquirer of its assets or the corporation with which it shall consolidate or
into which it shall merge shall (i) be a corporation organized under the laws of
one of the states of the United States of America, (ii) be qualified to do
business in the State, and (iii) assume in writing all of the obligations of the
Company under this Agreement and the Tax Agreement. Any transfer of all or
substantially all of the Company's generation assets shall not be deemed to
constitute a "disposition of all or substantially all of the Company's assets"
within the meaning of the preceding paragraph. Any such transfer of the
Company's generation assets shall not relieve the Company of any of its
obligations under this Agreement.
The Company hereby agrees that so long as any of the Bonds are insured by a
Bond Insurance Policy issued by the Bond Insurer and the Bond Insurer shall not
have failed to comply with its payment obligations under such Policy, in the
event of a Reorganization, unless otherwise consented to by the Bond Insurer,
the obligations of the Company under, and in respect of, the Bonds, the G&R
Notes, the G&R Indenture and the Agreement shall be assumed by, and shall become
direct and primary obligations of, a Regulated Utility Company such that at all
times the obligor under this Agreement and the obligor on the G&R Notes is a
Regulated Utility Company. The Company shall deliver to the Bond Insurer a
certificate of the president, any vice president or the treasurer and an opinion
of counsel reasonably acceptable to the Bond Insurer stating in each case that
such Reorganization complies with the provisions of this paragraph.
The Company need not comply with any of the provisions of this Section 5.1
if, at the time of such merger or consolidation, the Bonds will be defeased as
provided in Article VIII of the Indenture. The Company need not comply with the
provisions of the second paragraph of this Section 5.1 if the Bonds are redeemed
as provided in Section 3.01(B)(3) of the Indenture or if the Bond Insurance
Policy is terminated as described in Section 3.06 of the Indenture in connection
with a purchase of the Bonds by the Company in lieu of their redemption.
SECTION 5.2. ANNUAL STATEMENT. The Company agrees to have an annual audit
made by its regular independent certified public accountants and to furnish the
Trustee (within 30 days after receipt by the Company) with a balance sheet and
statement of income and surplus showing the financial condition of the Company
and its consolidated subsidiaries, if any, at the close of each fiscal year and
the results of operations of the Company and its consolidated subsidiaries, if
any, for each fiscal year, accompanied by a report of said accountants that such
statements have
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been prepared in accordance with generally accepted accounting principles. The
Company's obligations under this Section 5.2 may be satisfied by delivering a
copy of the Company's Annual Report on Form 10-K to the Trustee within 10 days
after it is filed with the Securities and Exchange Commission.
Delivery of such reports, information and documents to the Trustee is for
informational purposes only and the Trustee's receipt of such shall not
constitute constructive notice of any information contained therein or
determinable from information contained therein, including the Company's
compliance with any of its covenants hereunder (as to which the Trustee is
entitled to rely exclusively on officer's certificates).
SECTION 5.3. MAINTENANCE AND REPAIR; INSURANCE; TAXES; DISPOSITION. For so
long as the Company shall own the Project, (i) the Company shall maintain or
cause to be maintained the Project in good repair and keep it properly insured
and shall promptly pay or cause to be paid all costs thereof, and (ii) the
Company shall promptly pay or cause to be paid all installments of taxes,
installments of special assessments, and all governmental, utility and other
charges with respect to the Project, when due. The Company may, at its own
expense and in its own name in good faith contest or appeal any such taxes,
assessments or other charges, or installments thereof, but shall not permit any
such taxes, assessments or other charges, or installments thereof, to remain
unpaid if such nonpayment shall subject the Project or any part thereof to loss
or forfeiture. The Company, subject to the provisions of Section 3.4 hereof, is
not required by this Agreement to operate, or cause to be operated, any portion
of the Project after the Company shall deem in its discretion that such
continued operation by the Company is not advisable, and in such event the
Company may sell, lease or retire all or any such portion of the Project.
Subject to the provisions of Section 3.4 hereof, the net proceeds from such
sale, lease or other disposition, if any, shall belong to, and may be used for
any lawful purpose by, the Company. Upon disposition of the Project in its
entirety by the Company in accordance with this Section 5.3, the Company shall
be discharged from its obligations to operate, maintain, repair and insure the
Project as set forth in this Section 5.3. Any such sale, lease or other
disposition shall comply with the requirements of the Tax Agreement. Under any
and all circumstances, the Issuer shall have no obligation whatsoever with
respect to the operation, maintenance, repair or insurance of the Project.
SECTION 5.4. RECORDATION AND OTHER INSTRUMENTS. The Company shall cause
such security agreements, financing statements and all supplements thereto and
other instruments as may be required from time to time to be kept, to be
recorded and filed in such manner and in such places as may be required by law
in order to fully preserve, protect and perfect the security of the Owners of
the Bonds and the rights of the Trustee, and to perfect the security interest
created by the Indenture. The Company agrees to abide by the provisions of
Section 5.11 of the Indenture to the extent applicable to the Company.
SECTION 5.5. NO WARRANTY BY THE ISSUER. The Issuer makes no warranty,
either express or implied, as to the Project or that it will be suitable for the
purposes of the Company or needs of the Company.
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SECTION 5.6. AGREEMENT AS TO OWNERSHIP OF THE PROJECT. The Issuer and the
Company agree that title to the Project shall not be in the Issuer, and that the
Issuer shall have no interest in the Project.
SECTION 5.7. COMPANY TO FURNISH NOTICE OF RATE PERIOD ADJUSTMENTS;
LIQUIDITY FACILITY REQUIREMENTS; AUCTION RATE PERIOD PROVISIONS. The Company is
hereby granted the option to designate from time to time changes in Rate Periods
(and to rescind such changes) in the manner and to the extent set forth in
Section 2.03 of the Indenture. In the event the Company elects to exercise any
such option, the Company agrees that it shall cause notices of adjustments of
Rate Periods (or rescissions thereof) to be given to the Issuer, the Trustee and
the Remarketing Agent in accordance with Section 2.03(a), (b), (c), (d) or (e)
of the Indenture, and a copy of each such notice shall also be given at such
time to S&P and Moody's.
The Company hereby agrees that, so long as the Bonds are insured by a Bond
Insurance Policy issued by the Bond Insurer and notwithstanding the provisions
of Section 2.03 of the Indenture, it shall not give notice of its intention to
adjust the Rate Period for the Bonds to a Daily Rate Period, a Weekly Rate
Period or a Flexible Rate Period until the Company shall provide a liquidity
facility reasonably acceptable to the Bond Insurer from a liquidity facility
provider reasonably acceptable to the Bond Insurer in accordance with the Bond
Insurer's liquidity facility requirements to be effective on the related date of
adjustment.
If during any Auction Rate Period (i) consisting of Auction Periods of 35
days or less, the Bonds shall bear interest at the Maximum Interest Rate for a
period in excess of 180 days, or (ii) consisting of one Auction Period of 180
days or more, the Bonds shall bear interest at the Maximum Interest Rate for
such Period, the Company shall notify the Bond Insurer in writing of such event
and agrees to cooperate with the Bond Insurer to take all steps reasonably
necessary to adjust the Rate Period on the Bonds as soon as reasonably
practicable in accordance with the provisions of the Indenture to the Rate
Period which the Remarketing Agent advises the Company and the Bond Insurer will
be the lowest interest rate (taking into account all relevant costs) which would
enable the Remarketing Agent to sell all the Bonds on the date of such
adjustment at a price equal to 100% of the principal amount thereof (the "Lowest
Interest Rate Period"). If at such time the Company shall be in default under
the Agreement but the Bond Insurer shall not have failed to comply with its
payment obligations under the Bond Insurance Policy, the Bond Insurer may, in
its discretion, direct the Company to provide notice of the adjustment of the
Rate Period on the Bonds to the Lowest Interest Rate Period in accordance with
the provisions of Section 2.03 of the Indenture.
SECTION 5.8. INFORMATION REPORTING, ETC. The Issuer covenants and agrees
that, upon the direction of the Company or Bond Counsel, it will mail or cause
to be mailed to the Secretary of the Treasury (or his designee as prescribed by
regulation, currently the Internal Revenue Service Center, Ogden, Utah) a
statement setting forth the information required by Section 149(e) of the Code,
which statement shall be in the form of the Information Return for Tax-Exempt
Private Activity Bond Issues (Form 8038) of the Internal Revenue Service (or any
successor form) and which shall be completed by the Company and Bond Counsel
based in part upon information supplied by the Company and Bond Counsel.
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SECTION 5.9. LIMITED LIABILITY OF ISSUER. Any obligation or liability of
the Issuer created by or arising out of this Agreement or otherwise incurred in
connection with the issuance of the Bonds (including without limitation any
liability created by or arising out of the representations, warranties or
covenants set forth herein or otherwise) shall not impose a debt or pecuniary
liability upon the Issuer or the State or any political subdivision thereof, or
a charge upon the general credit or taxing powers of any of the foregoing, but
shall be payable solely out of the Revenues or other amounts payable by the
Company to the Issuer hereunder or otherwise (including without limitation any
amounts derived from indemnifications given by the Company).
Neither the issuance of the Bonds nor the delivery of this Agreement shall,
directly or indirectly or contingently, obligate the Issuer or the State or any
political subdivision thereof to levy any form of taxation therefor or to make
any appropriation for their payment. Nothing in the Bonds or in the Indenture or
this Agreement or the proceedings of the Issuer authorizing the Bonds or in the
Act or in any other related document shall be construed to authorize the Issuer
to create a debt of the Issuer or the State or any political subdivision thereof
within the meaning of any constitutional or statutory provision of the State.
The principal of, and premium, if any, and interest on, the Bonds shall be
payable solely from the funds pledged for their payment in accordance with the
Indenture and available therefor under this Agreement. Neither the State nor any
political subdivision thereof shall in any event be liable for the payment of
the principal of, premium, if any, or interest on, the Bonds or for the
performance of any pledge, obligation or agreement of any kind whatsoever which
may be undertaken by the Issuer. No breach of any such pledge, obligation or
agreement may impose any pecuniary liability upon the Issuer or the State or any
political subdivision thereof, or any charge upon the general credit or against
the taxing power of the Issuer or the State or any political subdivision
thereof.
SECTION 5.10. INSPECTION OF PROJECT. The Company agrees that the Issuer and
the Trustee and their duly authorized representatives shall have the right at
all reasonable times to enter upon and examine and inspect the Project property
and shall also be permitted, at all reasonable times, to examine the books and
records of the Company insofar as they relate to the Project.
SECTION 5.11. INDENTURE COVENANTS. The Company covenants to observe and
perform all of the obligations imposed on it under the Indenture.
ARTICLE VI
EVENTS OF DEFAULT AND REMEDIES
SECTION 6.1. EVENTS OF DEFAULT DEFINED. The following shall be "events of
default" under this Agreement and the terms "event of default" or "default"
shall mean, whenever they are used in this Agreement, any one or more of the
following events:
(a) Failure by the Company to pay when due any amounts required to be
paid under Section 4.2(a) hereof, which failure results in an event of
default under subparagraph (a) or (b) of Section 9.01 of the Indenture; or
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(b) Failure by the Company to pay or cause to be paid any payment
required to be paid under Section 4.2(b) hereof, which failure results in
an event of default under subparagraph (c) of Section 9.01 of the
Indenture; or
(c) Failure by the Company to observe and perform any covenant,
condition or agreement on its part to be observed or performed in this
Agreement, other than as referred to in (a) and (b) above, for a period of
90 days after written notice, specifying such failure and requesting that
it be remedied and stating that such notice is a "Notice of Default"
hereunder, given to the Company by the Trustee or to the Company and the
Trustee by the Issuer, unless the Issuer and the Trustee shall agree in
writing to an extension of such time prior to its expiration; provided,
however, if the failure stated in the notice cannot be corrected within the
applicable period, the Issuer and the Trustee will not unreasonably
withhold their consent to an extension of such time if corrective action is
instituted within the applicable period and diligently pursued until the
failure is corrected and such corrective action or diligent pursuit is
evidenced to the Trustee by a certificate of an Authorized Company
Representative; or
(d) A proceeding or case shall be commenced, without the application
or consent of the Company, in any court of competent jurisdiction seeking
(i) liquidation, reorganization, dissolution, winding-up or composition or
adjustment of debts, (ii) the appointment of a trustee, receiver,
custodian, liquidator or the like of the Company or of all or any
substantial part of its assets, or (iii) similar relief under any law
relating to bankruptcy, insolvency, reorganization, winding-up or
composition or adjustment of debts, and such proceeding or cause shall
continue undismissed, or an order, judgment, or decree approving or
ordering any of the foregoing shall be entered and shall continue in effect
for a period of 90 days; or an order for relief against the Company shall
be entered against the Company in an involuntary case under the Bankruptcy
Code (as now or hereafter in effect) or other applicable law; or
(e) The Company shall admit in writing its inability to pay its debts
generally as they become due or shall file a petition in voluntary
bankruptcy or shall make any general assignment for the benefit of its
creditors, or shall consent to the appointment of a receiver or trustee of
all or substantially all of its property, or shall commence a voluntary
case under the Bankruptcy Code (as now or hereafter in effect), or shall
file in any court of competent jurisdiction a petition seeking to take
advantage of any other law relating to bankruptcy, insolvency,
reorganization, winding-up or composition or adjustment of debts, or shall
fail to controvert in a timely or appropriate manner, or acquiesce in
writing to, any petition filed against it in an involuntary case under such
Bankruptcy Code or other applicable law; or
(f) Dissolution or liquidation of the Company; provided that the term
"dissolution or liquidation of the Company" shall not be construed to
include the cessation of the corporate existence of the Company resulting
either from a merger or consolidation of the Company into or with another
corporation or a dissolution or liquidation of the Company following a
transfer of all or substantially all of its assets as
-16-
an entirety, under the conditions permitting such actions contained in
Section 5.1 hereof; or
(g) The occurrence of an "event of default" under the Indenture.
The foregoing provisions of Section 6.1(c) are subject to the following
limitations: If by reason of Force Majeure the Company is unable in whole or in
part to carry out its agreements on its part herein contained, other than the
obligations on the part of the Company contained in Article IV and Sections 5.3
and 6.4 hereof, the Company shall not be deemed in default during the
continuance of such inability. The Company agrees, however, to remedy with all
reasonable dispatch the cause or causes preventing the Company from carrying out
its agreements; provided that the settlement of strikes, lockouts and other
industrial disturbances shall be entirely within the discretion of the Company
and the Company shall not be required to make settlement of strikes, lockouts
and other industrial disturbances by acceding to the demands of the opposing
party or parties when such course is in the sole judgment of the Company
unfavorable to the Company.
SECTION 6.2. REMEDIES ON DEFAULT. Whenever any event of default referred to
in Section 6.1 hereof shall have happened and be continuing, the Trustee, as
assignee of the Issuer:
(a) shall, by notice in writing to the Company, declare the unpaid
indebtedness under Section 4.2(a) hereof to be due and payable immediately,
if concurrently with or prior to such notice the unpaid principal amount of
the Bonds shall have been declared to be due and payable, and upon any such
declaration the same (being an amount sufficient, together with other
moneys available therefor in the Bond Fund, to pay the unpaid principal of,
premium, if any, and interest accrued on, the Bonds) shall become and shall
be immediately due and payable as liquidated damages; and
(b) may take whatever action at law or in equity as may appear
necessary or desirable to collect the payments and other amounts then due
and thereafter to become due hereunder or to enforce performance and
observance of any obligation, agreement or covenant of the Company under
this Agreement.
Any amounts collected pursuant to action taken under this Section 6.2 shall
be paid into the Bond Fund (unless otherwise provided in this Agreement) and
applied in accordance with the provisions of the Indenture. No action taken
pursuant to this Section 6.2 shall relieve the Company from the Company's
obligations pursuant to Section 4.2 hereof.
No recourse shall be had for any claim based on this Agreement against any
officer, director or stockholder, past, present or future, of the Company as
such, either directly or through the Company, under any constitutional
provision, statute or rule of law, or by the enforcement of any assessment or by
any legal or equitable proceeding or otherwise.
Nothing herein contained shall be construed to prevent the Issuer from
enforcing directly any of its rights under Sections 4.2(e), 4.2(g), 5.3 and 6.4
hereof.
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The Company shall promptly notify the Issuer of any action taken by the
Company under the grant of authority from the Issuer under the last paragraph of
Section 9.01 of the Indenture.
SECTION 6.3. NO REMEDY EXCLUSIVE. No remedy herein conferred upon or
reserved to the Issuer is intended to be exclusive of any other available remedy
or remedies, but each and every such remedy shall be cumulative and shall be in
addition to every other remedy given under this Agreement or now or hereafter
existing at law or in equity or by statute. No delay or omission to exercise any
right or power accruing upon any default shall impair any such right or power or
shall be construed to be a waiver thereof, but any such right and power may be
exercised from time to time and as often as may be deemed expedient. In order to
entitle the Issuer or the Trustee to exercise any remedy reserved to it in this
Article, it shall not be necessary to give any notice, other than such notice as
may be herein expressly required. Subject to the provisions of the Indenture and
hereof, such rights and remedies as are given the Issuer hereunder shall also
extend to the Trustee. The Owners of the Bonds, subject to the provisions of the
Indenture, shall be entitled to the benefit of all covenants and agreements
herein contained.
SECTION 6.4. AGREEMENT TO PAY FEES AND EXPENSES OF COUNSEL. In the event
the Company should default under any of the provisions of this Agreement and the
Issuer or the Trustee should employ Counsel or incur other expenses for the
collection of the indebtedness hereunder or the enforcement of performance or
observance of any obligation or agreement on the part of the Company herein
contained, the Company agrees that it will on written demand therefor pay to the
Trustee or the Issuer (or to the Counsel for either of such parties if directed
by such party), the reasonable fees and expenses of such Counsel and such other
expenses so incurred by or on behalf of the Issuer or the Trustee.
SECTION 6.5. NO ADDITIONAL WAIVER IMPLIED BY ONE WAIVER; CONSENTS TO
WAIVERS. In the event any agreement contained in this Agreement should be
breached by either party and thereafter waived by the other party, such waiver
shall be limited to the particular breach so waived and shall not be deemed to
waive any other breach hereunder. No waiver shall be effective unless in writing
and signed by the party making the waiver. The Issuer shall have no power to
waive any default hereunder by the Company without the consent of the Trustee to
such waiver. The Trustee shall have the power to waive any default by the
Company hereunder, except a default under Section 3.4, 4.2(e), 4.2(g), 5.3 or
6.4 hereof, in so far as it pertains to the Issuer, without the prior written
concurrence of the Issuer. Notwithstanding the foregoing, if, after the
acceleration of the maturity of the outstanding Bonds by the Trustee pursuant to
Section 9.02 of the Indenture, (i) all arrears of principal of and interest on
the outstanding Bonds and interest on overdue principal and (to the extent
permitted by law) on overdue installments of interest at the rate of interest
borne by the Bonds on the date on which such principal or interest became due
and payable and the premium, if any, on all Bonds then Outstanding which have
become due and payable otherwise than by acceleration, and all other sums
payable under the Indenture, except the principal of and the interest on such
Bonds which by such acceleration shall have become due and payable, shall have
been paid, (ii) all other things shall have been performed in respect of which
there was a default, (iii) there shall have been paid the reasonable fees and
expenses of the Trustee and of the Owners of such Bonds, including reasonable
attorneys' fees paid or incurred and (iv) such event of default under the
Indenture shall be waived in accordance with Section 9.09 of the Indenture with
the consequence that such
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acceleration under Section 9.02 of the Indenture is rescinded, then the
Company's default hereunder shall be deemed to have been waived and its
consequences rescinded and no further action or consent by the Trustee or the
Issuer shall be required; provided that there has been furnished an opinion of
Bond Counsel to the effect that such waiver will not adversely affect the
exemption from federal income taxes of interest on the Bonds.
ARTICLE VII
OPTIONS AND OBLIGATIONS OF COMPANY;
PREPAYMENTS; REDEMPTION OF BONDS
SECTION 7.1. OPTION TO PREPAY. The Company shall have, and is hereby
granted, the option to prepay the payments due hereunder in whole or in part at
any time or from time to time (a) to provide for the redemption of Bonds
pursuant to the provisions of Section 3.01(A) of the Indenture or (b) to
provide for the defeasance of the Bonds pursuant to Article VIII of the
Indenture. In the event the Company elects to provide for the redemption of
Bonds as permitted by this Section, the Company shall notify and instruct the
Trustee in accordance with Section 7.3 hereof to redeem all or any portion of
the Bonds in advance of maturity. If the Company so elects, any redemption of
Bonds pursuant to Section 3.01(A) of the Indenture may be made conditional.
SECTION 7.2. OBLIGATION TO PREPAY. The Company covenants and agrees that if
all or any part of the Bonds are unconditionally called for redemption in
accordance with the Indenture or become subject to mandatory redemption (except
as otherwise provided in Section 3.02 of the Indenture), it will prepay the
indebtedness hereunder in whole or in part in an amount sufficient to redeem
such Bonds on the date fixed for the redemption of such Bonds.
SECTION 7.3. NOTICE OF PREPAYMENT. Upon the exercise of the option granted
to the Company in Section 7.1 hereof, or upon the Company having knowledge of
the occurrence of any event requiring mandatory redemption of the Bonds in
accordance with Section 3.01(B) of the Indenture, the Company shall give written
notice to the Issuer, the Remarketing Agent, the Auction Agent and the Trustee.
The notice shall provide for the date of the application of the prepayment made
by the Company hereunder to the retirement of the Bonds in whole or in part
pursuant to call for redemption and shall be given by the Company not less than
five Business Days prior to the date notice of such redemption must be given by
the Trustee to the Bondholders as provided in Section 3.02 of the Indenture or
such later date as is acceptable to the Trustee and the Issuer.
ARTICLE VIII
MISCELLANEOUS
SECTION 8.1. NOTICES. (a) Except as otherwise provided herein, all notices,
certificates or other communications hereunder shall be sufficiently given if in
writing and shall be deemed given when mailed by first class mail, postage
prepaid, or by qualified overnight courier service,
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courier charges prepaid, or by facsimile (receipt of which is orally confirmed)
addressed as follows: if to the Issuer, at 1001 East Ninth Street, Building A,
Room 225, Reno, Nevada 89512, or to telecopy number (775) 328-2037, Attention:
Finance Director; if to the Company, at 6100 Neil Road, Reno, Nevada 89520, or
to telecopy number (702) 227-2250, Attention: Treasurer; if to the Trustee, at
385 Rifle Camp Road, West Paterson, New Jersey 07424, or to telecopy number
(973) 357-7840, Attention: Corporate Trust Services; if to the Remarketing
Agent, at the address set forth in the Remarketing Agreement, if any; and if to
the Auction Agent, at the address set forth in the Auction Agreement, if any. In
case by reason of the suspension of regular mail service, it shall be
impracticable to give notice by first class mail of any event to the Issuer, to
the Company, to the Remarketing Agent, to the Auction Agent when such notice is
required to be given pursuant to any provisions of this Agreement, then any
manner of giving such notice as shall be satisfactory to the Trustee shall be
deemed to be sufficient giving of such notice. The Issuer, the Company, the
Trustee, the Remarketing Agent and the Auction Agent may, by notice pursuant to
this Section 8.1, designate any different addresses to which subsequent notices,
certificates or other communications shall be sent.
(b) The Trustee agrees to accept and act upon instructions or
directions pursuant to this Agreement sent by unsecured e-mail, facsimile
transmission or other similar unsecured electronic methods, provided,
however, that (a) the Company and/or Issuer, subsequent to such
transmission of written instructions, shall, upon request by the Trustee,
provide the originally executed instructions or directions to the Trustee,
(b) upon request by the Trustee, such originally executed instructions or
directions shall be signed by a person as may be designated and authorized
to sign for the Company and/or Issuer or in the name of the Company and/or
Issuer, by an authorized representative of the Company and/or Issuer, and
(c) upon the request by the Trustee, the Company and/or Issuer shall
provide to the Trustee an incumbency certificate listing such designated
persons, which incumbency certificate shall be amended whenever a person is
to be added or deleted from the listing. If the Company and/or Issuer
elects to give the Trustee e-mail or facsimile instructions (or
instructions by a similar electronic method) and the Trustee elects to act
upon such instructions, the Trustee's reasonable interpretation and
understanding of such instructions shall be deemed controlling. The Trustee
shall not be liable for any losses, costs or expenses arising directly or
indirectly from the Trustee's reasonable reliance upon and compliance with
such instructions notwithstanding that such instructions conflict or are
inconsistent with a subsequent written instruction.
SECTION 8.2. ASSIGNMENTS. This Agreement may not be assigned by either
party without consent of the other and the Trustee, except that the Issuer shall
assign to the Trustee its rights under this Agreement (except under Sections
4.2(e), 4.2(g), 5.3, and 6.4 hereof) as provided by Section 4.4 hereof, and the
Company may assign its rights under this Agreement to any transferee or any
surviving or resulting corporation as provided by Section 5.1 hereof.
SECTION 8.3. SEVERABILITY. If any provision of this Agreement shall be held
or deemed to be or shall, in fact, be illegal, inoperative or unenforceable, the
same shall not affect any other provision or provisions herein contained or
render the same invalid, inoperative, or unenforceable to any extent whatever.
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SECTION 8.4. EXECUTION OF COUNTERPARTS. This Agreement may be
simultaneously executed in several counterparts, each of which shall be an
original and all of which shall constitute but one and the same instrument.
SECTION 8.5. AMOUNTS REMAINING IN BOND FUND. It is agreed by the parties
hereto that after payment in full of (i) the Bonds (or provision for payment
thereof having been made in accordance with the provisions of the Indenture),
(ii) the fees, charges and expenses of the Trustee in accordance with the
Indenture, (iii) the Administrative Expenses, (iv) the fees and expenses of the
Remarketing Agent, the Auction Agent and the Issuer and (v) all other amounts
required to be paid under this Agreement and the Indenture, any amounts
remaining in the Bond Fund shall belong to and be paid to the Company by the
Trustee.
SECTION 8.6. AMENDMENTS, CHANGES AND MODIFICATIONS. This Agreement may be
amended, changed, modified, altered or terminated only by written instrument
executed by the Issuer and the Company, and only if the written consent of the
Trustee thereto is obtained, and only in accordance with the provisions of
Article XII of the Indenture.
SECTION 8.7. GOVERNING LAW. This Agreement shall be governed exclusively by
and construed in accordance with the applicable laws of the State.
SECTION 8.8. AUTHORIZED ISSUER AND COMPANY REPRESENTATIVES. Whenever under
the provisions of this Agreement the approval of the Issuer or the Company is
required to take some action at the request of the other, such approval of such
request shall be given for the Issuer by the Authorized Issuer Representative
and for the Company by the Authorized Company Representative, and the other
party hereto and the Trustee shall be authorized to act on any such approval or
request and neither party hereto shall have any complaint against the other or
against the Trustee as a result of any such action taken.
SECTION 8.9. TERM OF THE AGREEMENT. This Agreement shall be in full force
and effect from its date to and including such date as all of the Bonds issued
under the Indenture shall have been fully paid or retired (or provision for such
payment shall have been made as provided in the Indenture), provided that all
representations and certifications by the Company as to all matters affecting
the tax-exempt status of the Bonds and the covenants of the Company in Sections
4.2(c), 4.2(d), 4.2(e), 4.2(f) and 4.2(g) hereof shall survive the termination
of this Agreement.
SECTION 8.10. CANCELLATION AT EXPIRATION OF TERM. At the acceleration,
termination or expiration of the term of this Agreement and following full
payment of the Bonds or provision for payment thereof and of all other fees and
charges having been made in accordance with the provisions of this Agreement and
the Indenture, the Issuer shall deliver to the Company any documents and take or
cause the Trustee to take such actions as may be necessary to effectuate the
cancellation and evidence the termination of this Agreement.
SECTION 8.11. BOND INSURANCE. The payment of the principal of and interest
on the Bonds when due is to be insured under, and to the extent provided in, the
Bond Insurance Policy, including the endorsements thereto, to be issued by the
Bond Insurer, and the Issuer and the
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Company agree to be bound by the provisions contained in Appendix C to the
Indenture and the Company agrees to be bound by the provisions contained in the
Insurance Agreement. In the event of any conflict between the provisions of
Appendix C to the Indenture and the provisions of this Agreement, the provisions
of Appendix C shall govern and control.
All references in this Agreement to the Bond Insurer shall only apply so
long as a Bond Insurance Policy issued by the Bond Insurer is in effect for any
of the Bonds (and the Bond Insurer has not failed to comply with its payment
obligations under the Bond Insurance Policy).
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IN WITNESS WHEREOF, the Issuer and the Company have caused this Agreement
to be executed in their respective corporate names and their respective
corporate seals to be hereunto affixed and attested by their duly authorized
officers, all as of the date first above written.
WASHOE COUNTY, NEVADA
By
Chairman
Board of County Commissioners
(SEAL)
Attest:
County Clerk
SIERRA PACIFIC POWER COMPANY
By
Treasurer
(SEAL)
Attest:
Secretary
IN WITNESS WHEREOF, the Issuer and the Company have caused this Agreement
to be executed in their respective corporate names and their respective
corporate seals to be hereunto affixed and attested by their duly authorized
officers, all as of the date first above written.
WASHOE COUNTY, NEVADA
By
Chairman
Board of County Commissioners
(SEAL)
Attest:
County Clerk
SIERRA PACIFIC POWER COMPANY
By
Vice President, Finance and Risk, and
Treasurer
(SEAL)
Attest:
Secretary
Exhibit 10(D)
FINANCING AGREEMENT
Dated as of November 1, 2006
By and Between
WASHOE COUNTY, NEVADA
and
SIERRA PACIFIC POWER COMPANY
RELATING TO
WATER FACILITIES REFUNDING REVENUE BONDS
(SIERRA PACIFIC POWER COMPANY PROJECT)
SERIES 2006B
The amounts payable to the Issuer (except for amounts payable to, and
certain rights and privileges of, the Issuer under Sections 4.2(e), 4.2(g), 5.3
and 6.4 hereof and any rights of the Issuer to receive any notices,
certificates, requests, requisitions or communications hereunder) and certain
other rights of the Issuer under this Financing Agreement have been pledged and
assigned under the Indenture of Trust dated as of November 1, 2006, between the
Issuer and The Bank of New York, as Trustee.
FINANCING AGREEMENT
TABLE OF CONTENTS
(This Table of Contents is not a part of this Agreement
and is only for convenience of reference).
SECTION HEADING PAGE
------- ------- ----
ARTICLE I DEFINITIONS............................................. 1
ARTICLE II REPRESENTATIONS......................................... 5
Section 2.1. Representations and Covenants by the Issuer............. 5
Section 2.2. Representations by the Company.......................... 5
ARTICLE III ISSUANCE OF THE BONDS................................... 6
Section 3.1. Agreement to Issue Bonds; Application of Bond Proceeds.. 6
Section 3.2. Deposit of Additional Funds by Company.................. 6
Section 3.3. Investment of Moneys in the Bond Fund................... 6
Section 3.4. Tax Exempt Status of Bonds.............................. 7
ARTICLE IV LOAN AND PROVISIONS FOR REPAYMENT....................... 8
Section 4.1. Loan of Bond Proceeds................................... 8
Section 4.2. Loan Repayments and Other Amounts Payable............... 8
Section 4.3. No Defense or Set-Off................................... 10
Section 4.4. Payments Pledged and Assigned........................... 10
Section 4.5. Payment of the Bonds and Other Amounts.................. 10
ARTICLE V SPECIAL COVENANTS AND AGREEMENTS........................ 11
Section 5.1. Company to Maintain its Corporate Existence; Conditions
Under Which Exceptions Permitted..................... 11
Section 5.2. Annual Statement........................................ 12
Section 5.3. Reserved................................................ 12
Section 5.4. Recordation and Other Instruments....................... 12
Section 5.5. No Warranty by the Issuer............................... 12
Section 5.6. Agreement as to Ownership of the Project................ 12
Section 5.7. Company to Furnish Notice of Rate Period Adjustments;
Liquidity Facility Requirements; Auction Rate Period
Provisions........................................... 12
Section 5.8. Information Reporting, Etc.............................. 13
Section 5.9. Limited Liability of Issuer............................. 13
Section 5.10. Reserved................................................ 14
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Section 5.11. Indenture Covenants..................................... 14
ARTICLE VI EVENTS OF DEFAULT AND REMEDIES.......................... 14
Section 6.1. Events of Default Defined............................... 14
Section 6.2. Remedies on Default..................................... 16
Section 6.3. No Remedy Exclusive..................................... 16
Section 6.4. Agreement to Pay Fees and Expenses of Counsel........... 17
Section 6.5. No Additional Waiver Implied by One Waiver; Consents to
Waivers.............................................. 17
ARTICLE VII OPTIONS AND OBLIGATIONS OF COMPANY; PREPAYMENTS;
REDEMPTION OF BONDS.................................. 18
Section 7.1. Option to Prepay........................................ 18
Section 7.2. Obligation to Prepay.................................... 18
Section 7.3. Notice of Prepayment.................................... 18
ARTICLE VIII MISCELLANEOUS........................................... 18
Section 8.1. Notices................................................. 18
Section 8.2. Assignments............................................. 19
Section 8.3. Severability............................................ 19
Section 8.4. Execution of Counterparts............................... 19
Section 8.5. Amounts Remaining in Bond Fund.......................... 19
Section 8.6. Amendments, Changes and Modifications................... 20
Section 8.7. Governing Law........................................... 20
Section 8.8. Authorized Issuer and Company Representatives........... 20
Section 8.9. Term of the Agreement................................... 20
Section 8.10. Cancellation at Expiration of Term...................... 20
Section 8.11. Bond Insurance.......................................... 20
Signature................................................................ 21
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THIS FINANCING AGREEMENT made and entered into as of November 1, 2006, by
and between WASHOE COUNTY, NEVADA, a political subdivision of the State of
Nevada, party of the first part (hereinafter referred to as the "Issuer"), and
SIERRA PACIFIC POWER COMPANY, a corporation duly organized and existing under
the laws of the State of Nevada, party of the second part (hereinafter referred
to as the "Company"),
WITNESSETH:
In consideration of the respective representations and agreements
hereinafter contained, the parties hereto agree as follows (provided, that in
the performance of the agreements of the Issuer herein contained, any obligation
it may thereby incur shall not constitute or give rise to a pecuniary liability
or a charge upon its general credit or against its taxing powers but shall be
payable solely out of the Revenues (as hereinafter defined) derived from this
Financing Agreement and the Bonds, as hereinafter defined):
ARTICLE I
DEFINITIONS
The following terms shall have the meanings specified in this Article
unless the context clearly requires otherwise. The singular shall include the
plural and the masculine shall include the feminine.
"Act" means the County Economic Development Revenue Bond Law, as amended,
contained in Sections 244A.669 to 244A.763, inclusive, of the Nevada Revised
Statutes.
"Administrative Expenses" means the reasonable and necessary expenses
(including the reasonable value of employee services and fees of Counsel)
incurred by the Issuer in connection with the Bonds, this Agreement, the
Indenture and any transaction or event contemplated by this Agreement or the
Indenture.
"Agreement" means this Financing Agreement by and between the Issuer and
the Company, as from time to time amended and supplemented.
"Auction Agent" means the auction agent appointed in accordance with the
provisions of the Indenture.
"Authorized Company Representative" means any person who, at the time,
shall have been designated to act on behalf of the Company by a written
certificate furnished to the Issuer, the Remarketing Agent and the Trustee
containing the specimen signature of such person and signed on behalf of the
Company by any officer of the Company. Such certificate may designate an
alternate or alternates.
"Authorized Issuer Representative" means any person at the time designated
to act on behalf of the Issuer by a written certificate furnished to the Company
and the Trustee containing the specimen signature of such person and signed on
behalf of the Issuer by its Chairman. Such certificate may designate an
alternate or alternates.
"Bankruptcy Code" means the United States Bankruptcy Reform Act of 1978, as
amended from time to time, or any substitute or replacement legislation.
"Bond" or "Bonds" means the Issuer's bonds identified in Section 2.02 of
the Indenture.
"Bond Counsel" means the Counsel who renders the opinion as to the
tax-exempt status of interest on the Bonds or other nationally recognized
municipal bond counsel mutually acceptable to the Issuer and the Company.
"Bond Fund" means the fund created by Section 6.02 of the Indenture.
"Code" means the United States Internal Revenue Code of 1986, as amended,
and regulations promulgated or proposed thereunder.
"Company" means Sierra Pacific Power Company, a Nevada corporation, and its
successors and assigns and any surviving, resulting or transferee corporation as
permitted in Section 5.1 hereof.
"Counsel" means an attorney at law or a firm of attorneys (who may be an
employee of or counsel to the Issuer or the Company or the Trustee) duly
admitted to the practice of law before the highest court of any state of the
United States of America or of the District of Columbia.
"Delivery Agreement" means the Delivery Agreement dated the Dated Date,
between the Company and the Trustee, as amended, supplemented or restated from
time to time, pursuant to which the Company will issue to the Trustee the G&R
Notes at the time of the initial authentication and delivery of the Bonds.
"Escrow Agreement" means the Escrow Agreement dated as of the Dated Date
between the Company and the Series 1987 Trustee.
"Extraordinary Services" and "Extraordinary Expenses" means all services
rendered and all expenses (including fees and expenses of Counsel) incurred
under the Indenture and the Tax Agreement other than Ordinary Services and
Ordinary Expenses.
"Force Majeure" means acts of God, strikes, lockouts or other industrial
disturbances; acts of public enemies; orders or restraints of any kind of the
governments of the United States or of the State, or any of their departments,
agencies or officials, or any civil or military authority; insurrections; riots;
landslides; lightning; earthquakes; fires; tornadoes; volcanoes; storms;
droughts; floods; explosions, breakage, or malfunction or accident to machinery,
transmission
-2-
lines, pipes or canals, even if resulting from negligence; civil disturbances;
or any other cause not reasonably within the control of the Company.
"G&R Indenture" means the General and Refunding Mortgage Indenture dated as
of May 1, 2001 between the Company and the G&R Trustee, as amended and
supplemented.
"G&R Notes" means the Company's $75,000,000 General and Refunding Mortgage
Note, Series N, No. N-3, due March 1, 2036.
"G&R Trustee" means The Bank of New York, as trustee under the G&R
Indenture or any successor trustee.
"Governing Body" means the Board of County Commissioners of the Issuer.
"Hereof," "herein," "hereunder" and other words of similar import refer to
this Agreement as a whole.
"Indenture" means the Indenture of Trust relating to this Agreement between
the Issuer and The Bank of New York, as Trustee, of even date herewith, pursuant
to which the Bonds are authorized to be issued, including any indentures
supplemental thereto or amendatory thereof.
"Issuer" means Washoe County, Nevada, and any successor body to the duties
or functions of the Issuer.
"Ordinary Services" and "Ordinary Expenses" means those services normally
rendered and those expenses including fees and expenses of Counsel, normally
incurred by a trustee or paying agent under instruments similar to the Indenture
and the Tax Agreement.
"Owner" or "owner of Bonds" means the Person or Persons in whose name or
names a Bond shall be registered on books of the Issuer kept by the Registrar
for that purpose in accordance with the terms of the Indenture.
"Person" means natural persons, firms, partnerships, associations,
corporations, trusts and public bodies.
"Project" means the Project as defined in the Project Certificate.
"Project Certificate" means the Company's Project and Refunding
Certificate, delivered concurrently with the issuance of the Bonds, with respect
to certain facts which are within the knowledge of the Company and certain
reasonable assumptions of the Company, to enable Chapman and Cutler LLP, as Bond
Counsel, to determine that interest on the Bonds is not includable in the gross
income of the Owners of the Bonds for federal income tax purposes.
"Rebate Fund" means the Rebate Fund, if any, created and established
pursuant to the Tax Agreement.
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"Regulated Utility Company" means a corporation (or a limited liability
company) engaged in the distribution of electricity, gas and/or water and which
is regulated by the applicable public service commissions in all of the states
that comprise its service area.
"Remarketing Agent" means the remarketing agent, if any, appointed in
accordance with Section 4.08 of the Indenture and any permitted successor
thereto.
"Reorganization" means any reorganization, consolidation or merger of the
Company or its affiliates, or any transfer or lease of a substantial portion of
the assets of the Company or its affiliates, as a result of which the obligor
under the Agreement or the obligor on the G&R Notes ceases to be a Regulated
Utility Company.
"Series 1987 Bonds" means the Issuer's Variable Rate Demand Water
Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1987,
currently outstanding in the aggregate principal amount of $75,000,000.
"Series 1987 Indenture" means the Indenture of Trust dated June 1, 1987
between the Issuer and the Series 1987 Trustee, as trustee, pursuant to which
the Series 1987 Bonds were issued.
"Series 1987 Trustee" means The Bank of New York, as current trustee under
the Series 1987 Indenture.
"State" means the State of Nevada.
"Tax Agreement" means the Tax Exemption Certificate and Agreement with
respect to the Bonds, dated the date of delivery of the Bonds, among the
Company, the Issuer and the Trustee, as from time to time amended and
supplemented.
"Trust Estate" means the property conveyed to the Trustee pursuant to the
Granting Clauses of the Indenture.
"Trustee" means The Bank of New York, as Trustee under the Indenture, and
any successor Trustee appointed pursuant to Section 10.06 or 10.09 of the
Indenture at the time serving as Trustee thereunder, and any separate or
co-trustee serving as such thereunder.
All other terms used herein which are defined in the Indenture shall have
the same meanings assigned them in the Indenture unless the context otherwise
requires.
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ARTICLE II
REPRESENTATIONS
SECTION 2.1. REPRESENTATIONS AND COVENANTS BY THE ISSUER. The Issuer makes
the following representations and covenants as the basis for the undertakings on
its part herein contained:
(a) The Issuer is a duly organized and existing political subdivision
of the State of Nevada. Under the provisions of the Act, the Issuer is
authorized to enter into the transactions contemplated by this Agreement,
the Indenture and the Tax Agreement and to carry out its obligations
hereunder and thereunder. The Issuer has duly authorized the execution and
delivery of this Agreement, the Indenture and the Tax Agreement.
(b) The Bonds are to be issued under and secured by the Indenture,
pursuant to which certain of the Issuer's interests in this Agreement and
the Revenues derived by the Issuer pursuant to this Agreement will be
pledged and assigned as security for payment of the principal of, premium,
if any, and interest on, the Bonds.
(c) The Governing Body of the Issuer has found that the issuance of
the Bonds will further the public purposes of the Act.
(d) The Issuer has not assigned and will not assign any of its
interests in this Agreement other than pursuant to the Indenture.
(e) No member of the Governing Body of the Issuer, nor any other
officer of the Issuer, has any interest, financial (other than ownership of
less than one-tenth of one percent (.1%) of the publicly traded securities
issued by the Company or its affiliated corporations), employment or other,
in the Company or in the transactions contemplated hereby.
SECTION 2.2. REPRESENTATIONS BY THE COMPANY. The Company makes the
following representations as the basis for the undertakings on its part herein
contained:
(a) The Company is a corporation duly incorporated under the laws of
the State and is in good standing in the State, is qualified to do business
as a foreign corporation in all other states and jurisdictions wherein the
nature of the business transacted by the Company or the nature of the
property owned or leased by it makes such licensing or qualification
necessary, and has the power to enter into and by proper corporate action
has been duly authorized to execute and deliver this Agreement and the Tax
Agreement.
(b) Neither the execution and delivery of this Agreement, the Escrow
Agreement or the Tax Agreement, the consummation of the transactions
contemplated hereby and thereby, nor the fulfillment of or compliance with
the terms and conditions of this Agreement, the Escrow Agreement and the
Tax Agreement, conflicts with or results
-5-
in a breach of any of the terms, conditions or provisions of any corporate
restriction or any agreement or instrument to which the Company is now a
party or by which it is bound, or constitutes a default under any of the
foregoing, or results in the creation or imposition of any lien, charge or
encumbrance whatsoever upon any of the property or assets of the Company
under the terms of any instrument or agreement other than the Indenture.
(c) The statements, information and descriptions contained in the
Project Certificate and the Tax Agreement, as of the date hereof and at the
time of the delivery of the Bonds to the Underwriter, are and will be true,
correct and complete, do not and will not contain any untrue statement or
misleading statement of a material fact, and do not and will not omit to
state a material fact required to be stated therein or necessary to make
the statements, information and descriptions contained therein, in the
light of the circumstances under which they were made, not misleading.
ARTICLE III
ISSUANCE OF THE BONDS
SECTION 3.1. AGREEMENT TO ISSUE BONDS; APPLICATION OF BOND PROCEEDS. In
order to provide funds to lend to the Company to refund the Series 1987 Bonds as
provided in Section 4.1 hereof, the Issuer agrees that it will issue under the
Indenture, sell and cause to be delivered to the Underwriter, its Bonds in the
aggregate principal amount of $75,000,000, bearing interest and maturing as set
forth in the Indenture. The Issuer will thereupon deposit the proceeds received
from the sale of the Bonds as follows: (1) in the Bond Fund, a sum equal to the
accrued interest, if any, paid by the Underwriter; and (2) $75,000,000 with the
Series 1987 Trustee under the Escrow Agreement to be used as provided therein.
SECTION 3.2. DEPOSIT OF ADDITIONAL FUNDS BY COMPANY. The Company covenants
that it will deposit such additional amounts as may be required by the Escrow
Agreement to be deposited by the Company on the Dated Date with the Series 1987
Trustee. The Company covenants that it will comply with the terms of the Escrow
Agreement.
SECTION 3.3. INVESTMENT OF MONEYS IN THE BOND FUND. Except as otherwise
herein provided, any moneys held as a part of the Bond Fund shall be invested or
reinvested by the Trustee at the specific written direction of an Authorized
Company Representative as to specific investments, to the extent permitted by
law, in:
(a) bonds or other obligations of the United States of America;
(b) bonds or other obligations, the payment of the principal of and
interest on which is unconditionally guaranteed by the United States of
America;
(c) obligations issued or guaranteed as to principal and interest by
any agency or person controlled or supervised by and acting as an
instrumentality of the United
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States of America pursuant to authority granted by the Congress of the
United States of America;
(d) obligations issued or guaranteed by any state of the United States
of America, or any political subdivision of any such state, or in funds
consisting of such obligations to the extent described in Section
1.148-8(e)(3)(iii) of the 1992 Treasury Regulations;
(e) prime commercial paper;
(f) prime finance company paper;
(g) bankers' acceptances drawn on and accepted by commercial banks;
(h) repurchase agreements fully secured by obligations issued or
guaranteed as to principal and interest by the United States of America or
by any person controlled or supervised by and acting as an instrumentality
of the United States of America pursuant to authority granted by the
Congress of the United States of America;
(i) certificates of deposit issued by commercial banks, including
banks domiciled outside of the United States of America; and
(j) units of taxable government money market portfolios composed of
obligations guaranteed as to principal and interest by the United States of
America or repurchase agreements fully collateralized by such obligations.
The investments so purchased shall be held by the Trustee and shall be
deemed at all times a part of the fund and the accounts therein, if any, for
which they were made and the interest accruing thereon and any profit realized
therefrom shall be credited to such fund and the accounts therein, if any,
subject to the provisions of the Tax Agreement. The Company agrees that to the
extent any moneys in the Bond Fund represent moneys held for the payment of
particular Bonds, or to the extent that any moneys are held for the payment of
the purchase price of Bonds pursuant to Article IV of the Indenture, such moneys
shall not be invested.
SECTION 3.4. TAX EXEMPT STATUS OF BONDS. The Company covenants and agrees
that it has not taken or permitted and will not take or permit any action which
results in interest paid on the Bonds being included in gross income of the
holders or beneficial owners of the Bonds for purposes of federal income
taxation (other than a holder or beneficial owner who is a "substantial user" of
the Project or a "related person" within the meaning of Section 147(a) of the
Code). The Company covenants that none of the proceeds of the Bonds or the
payments to be made under this Agreement, or any other funds which may be deemed
to be proceeds of the Bonds pursuant to Section 148(a) of the Code, will be
invested or used in such a way, and that no actions will be taken or not taken,
as to cause the Bonds to be treated as "arbitrage bonds" within the meaning of
Section 148(a) of the Code. Without limiting the generality of the foregoing,
the Company covenants and agrees that it will comply with the provisions of the
Tax Agreement and the Project Certificate.
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For purposes of the immediately preceding paragraph, the Company will be
deemed to have taken or permitted or omitted to take any action which is taken
or permitted or omitted by Truckee Meadows Water Authority, the owner of the
Project, or any subsequent owner or operator of the Project or portion thereof.
The Company has received a certificate dated the Dated Date from Truckee Meadows
Water Authority with respect to the Project. This certificate is attached to the
Project Certificate.
ARTICLE IV
LOAN AND PROVISIONS FOR REPAYMENT
SECTION 4.1. LOAN OF BOND PROCEEDS. (a) The Issuer agrees, upon the terms
and conditions in this Agreement, to lend to the Company the proceeds (exclusive
of accrued interest, if any) received by the Issuer from the sale of the Bonds
in order to refund the Series 1987 Bonds, and the Company agrees to apply the
gross proceeds of such loan to the refunding of the Series 1987 Bonds as set
forth in Sections 3.1 and 3.2 hereof.
(b) The Issuer and the Company expressly reserve the right to enter into,
to the extent permitted by law, an agreement or agreements other than this
Agreement, with respect to the issuance by the Issuer, under an indenture or
indentures other than the Indenture, of obligations to provide additional funds
to refund all or any principal amount of the Bonds.
SECTION 4.2. LOAN REPAYMENTS AND OTHER AMOUNTS PAYABLE. (a) On each date
provided in or pursuant to the Indenture for the payment (whether at maturity or
upon redemption or acceleration) of principal of, and premium, if any, and
interest on, the Bonds, until the principal of, and premium, if any, and
interest on, the Bonds shall have been fully paid or provision for the payment
thereof shall have been made in accordance with the Indenture, the Company shall
pay to the Trustee in immediately available funds, for deposit in the Bond Fund,
as a repayment installment of the loan of the proceeds of the Bonds pursuant to
Section 4.1(a) hereof, a sum equal to the amount payable on such date (whether
at maturity or upon redemption or acceleration) as principal of, and premium, if
any, and interest on, the Bonds as provided in the Indenture; provided, however,
that the obligation of the Company to make any such repayment installment shall
be reduced by the amount of any moneys then on deposit in the Bond Fund and
available for such payment; and provided further, that the obligation of the
Company to make any such payment shall be deemed to be satisfied and discharged
to the extent provided for under a liquidity facility (if applicable) or under
the G&R Notes.
(b) The Company shall pay to the Trustee amounts equal to the amounts to be
paid by the Trustee for the purchase of Bonds pursuant to Article IV of the
Indenture. Such amounts shall be paid by the Company to the Trustee in
immediately available funds on the date such payments pursuant to Section 4.05
of the Indenture are to be made; provided, however, that the obligation of the
Company to make any such payment shall be deemed to be satisfied and discharged
to the extent moneys are available from the source described in clause (i) of
Section 4.05(a) of the Indenture and to the extent moneys are available under
any liquidity facility (if applicable).
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(c) The Company agrees to pay to the Trustee (i) the fees of the
Trustee for the Ordinary Services rendered by it and an amount equal to the
Ordinary Expenses incurred by it under the Indenture and the Tax Agreement,
as and when the same become due, and (ii) the reasonable fees, charges and
expenses of the Trustee for reasonable Extraordinary Services and
Extraordinary Expenses, as and when the same become due, incurred under the
Indenture and the Tax Agreement. The Company agrees that the Trustee, its
officers, agents, servants and employees, shall not be liable for, and
agrees that it will at all times indemnify and hold harmless the Trustee,
its officers, agents, servants and employees against, and pay all expenses
of the Trustee, its officers, agents, servants and employees, relating to
any lawsuit, proceeding or claim and resulting from any action or omission
taken or made by or on behalf of the Trustee, its officers, agents,
servants and employees pursuant to this Agreement, the Indenture or the Tax
Agreement, that may be occasioned by any cause (other than the negligence
or willful misconduct of the Trustee, its officers, agents, servants and
employees). In case any action shall be brought against the Trustee in
respect of which indemnity may be sought against the Company, the Trustee
shall promptly notify the Company in writing and the Company shall be
entitled to assume control of the defense thereof, including the employment
of Counsel reasonably satisfactory to the Trustee and the payment of all
expenses. The Trustee shall have the right to employ separate Counsel in
any such action and participate in the defense thereof, but the fees and
expenses of such Counsel shall be paid by the Trustee unless (i) the
employment of such Counsel has been authorized by the Company, (ii) the
Trustee has determined (which determination may be based upon an opinion of
counsel delivered to the Trustee and furnished to the Company) that there
may be a conflict of interest of such Counsel retained by the Company
between the Company and the Trustee in the conduct of such defense, (iii)
the Company ceases or terminates the employment of such Counsel retained by
the Company or (iv) such Counsel retained by the Company withdraws with
respect to such defense. The Company shall not be liable for any settlement
of any such action without its consent, but if any such action is settled
with the consent of the Company or if there be final judgment for the
plaintiff in any such action, the Company agrees to indemnify and hold
harmless the Trustee from and against any loss or liability by reason of
such settlement or final judgment. The Company agrees that the
indemnification provided herein shall survive the termination of this
Agreement or the Indenture or the resignation of the Trustee. For purposes
of this Section 4.2(c), the Trustee is deemed a third party beneficiary of
this Agreement.
(d) The Company agrees to pay all costs incurred in connection with
the issuance of the Bonds from sources other than Bond proceeds and the
Issuer shall have no obligation with respect to such costs.
(e) The Company agrees to indemnify and hold harmless the Issuer and
any member, officer, official or employee of the Issuer against any and all
losses, costs, charges, expenses, judgments and liabilities created by or
arising out of this Agreement, the Indenture, the Remarketing Agreement,
the Auction Agreement, the Bond Purchase Agreement, any Broker- Dealer
Agreement or the Tax Agreement or otherwise incurred in connection with the
issuance of the Bonds. The Company agrees to pay the Issuer its Closing Fee
in connection with the issuance of the Bonds in the amount of $50,000. The
Issuer may submit to the Company periodic statements, not more frequently
than monthly, for its Administrative Expenses and the
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Company shall make payment to the Issuer of the full amount of each such
statement within 30 days after the Company receives such statement.
(f) The Company agrees to pay (i) to the Remarketing Agent the
reasonable fees, charges and expenses of such Remarketing Agent and (ii) to
the Auction Agent the reasonable fees, charges and expenses of such Auction
Agent, and the Issuer shall have no obligation or liability with respect to
the payment of any such fees, charges or expenses.
(g) In the event the Company shall fail to make any of the payments
required by (a) or (b) of this Section 4.2, the payment so in default shall
continue as an obligation of the Company until the amount in default shall
have been fully paid and the Company will pay interest to the extent
permitted by law, on any overdue amount at the rate of interest borne by
the Bonds on the date on which such amount became due and payable until
paid. In the event that the Company shall fail to make any of the payments
required by (c), (d), (e) or (f) of this Section 4.2, the payment so in
default shall continue as an obligation of the Company until the amount in
default shall have been fully paid, and the Company agrees to pay the same
with interest thereon to the extent permitted by law at a rate 1% above the
rate of interest then charged by the Trustee on 90-day commercial loans to
its prime commercial borrowers until paid.
SECTION 4.3. NO DEFENSE OR SET-OFF. The obligation of the Company to make
the payments pursuant to this Agreement shall be absolute and unconditional
without defense or set-off by reason of any default by the Issuer under this
Agreement or under any other agreement between the Company and the Issuer or for
any other reason, it being the intention of the parties that the payments
required hereunder will be paid in full when due without any delay or diminution
whatsoever.
SECTION 4.4. PAYMENTS PLEDGED AND ASSIGNED. It is understood and agreed
that all payments required to be made by the Company pursuant to Section 4.2
hereof (except payments made to the Trustee pursuant to Section 4.2(c) hereof,
to the Remarketing Agent and the Auction Agent pursuant to Section 4.2(f)
hereof, to the Issuer pursuant to Section 4.2(e) hereof and to any or all the
Issuer and the Trustee and the Remarketing Agent pursuant to Section 4.2(g)
hereof) and certain rights of the Issuer hereunder are pledged and assigned by
the Indenture. The Company consents to such pledge and assignment. The Issuer
hereby directs the Company and the Company hereby agrees to pay or cause to be
paid to the Trustee all said amounts except payments to be made to the
Remarketing Agent and the Auction Agent pursuant to Section 4.2(f) hereof and
payments to be made to the Issuer pursuant to Sections 4.2(e) and (g) hereof.
The Project will not constitute any part of the security for the Bonds, except
to the extent that the Trustee as holder of G&R Notes has a lien on property
under the G&R Indenture.
SECTION 4.5. PAYMENT OF THE BONDS AND OTHER AMOUNTS. The Bonds and interest
and premium, if any, thereon shall be payable solely from (i) payments made by
the Company to the Trustee under Section 4.2(a) hereof and (ii) other moneys on
deposit in the Bond Fund and available therefor.
Payments of principal of, and premium, if any, or interest on, the Bonds
with moneys in the Bond Fund constituting proceeds from the sale of the Bonds or
earnings on investments made
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under the provisions of the Indenture shall be credited against the obligation
to pay required by Section 4.2(a) hereof.
Whenever any Bonds are redeemable in whole or in part at the option of the
Company, the Trustee, on behalf of the Issuer, shall redeem the same upon the
request of the Company and such redemption (unless conditional) shall be made
from payments made by the Company to the Trustee under Section 4.2(a) hereof
equal to the redemption price of such Bonds.
Whenever payment or provision therefor has been made in respect of the
principal of, or premium, if any, or interest on, all or any portion of the
Bonds in accordance with the Indenture (whether at maturity or upon redemption
or acceleration or upon provision for payment in accordance with Article VIII of
the Indenture), payments shall be deemed paid to the extent such payment or
provision therefor has been made and is considered to be a payment of principal
of, or premium, if any, or interest on, such Bonds. If such Bonds are thereby
deemed paid in full, the Trustee shall notify the Company and the Issuer that
such payment requirement has been satisfied. Subject to the foregoing, or unless
the Company is entitled to a credit under this Agreement or the Indenture, all
payments shall be in the full amount required by Section 4.2(a) hereof.
ARTICLE V
SPECIAL COVENANTS AND AGREEMENTS
SECTION 5.1. COMPANY TO MAINTAIN ITS CORPORATE EXISTENCE; CONDITIONS UNDER
WHICH EXCEPTIONS PERMITTED. The Company agrees that during the term of this
Agreement, it will maintain its corporate existence and its good standing in the
State, will not dissolve or otherwise dispose of all or substantially all of its
assets and will not consolidate with or merge into another corporation unless
the acquirer of its assets or the corporation with which it shall consolidate or
into which it shall merge shall (i) be a corporation organized under the laws of
one of the states of the United States of America, (ii) be qualified to do
business in the State, and (iii) assume in writing all of the obligations of the
Company under this Agreement and the Tax Agreement. Any transfer of all or
substantially all of the Company's generation assets shall not be deemed to
constitute a "disposition of all or substantially all of the Company's assets"
within the meaning of the preceding paragraph. Any such transfer of the
Company's generation assets shall not relieve the Company of any of its
obligations under this Agreement.
The Company hereby agrees that so long as any of the Bonds are insured by a
Bond Insurance Policy issued by the Bond Insurer and the Bond Insurer shall not
have failed to comply with its payment obligations under such Policy, in the
event of a Reorganization, unless otherwise consented to by the Bond Insurer,
the obligations of the Company under, and in respect of, the Bonds, the G&R
Notes, the G&R Indenture and the Agreement shall be assumed by, and shall become
direct and primary obligations of, a Regulated Utility Company such that at all
times the obligor under this Agreement and the obligor on the G&R Notes is a
Regulated Utility Company. The Company shall deliver to the Bond Insurer a
certificate of the president, any vice president or the treasurer and an opinion
of counsel reasonably acceptable to the Bond
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Insurer stating in each case that such Reorganization complies with the
provisions of this paragraph.
The Company need not comply with any of the provisions of this Section 5.1
if, at the time of such merger or consolidation, the Bonds will be defeased as
provided in Article VIII of the Indenture. The Company need not comply with the
provisions of the second paragraph of this Section 5.1 if the Bonds are redeemed
as provided in Section 3.01(B)(3) of the Indenture or if the Bond Insurance
Policy is terminated as described in Section 3.06 of the Indenture in connection
with a purchase of the Bonds by the Company in lieu of their redemption.
SECTION 5.2. ANNUAL STATEMENT. The Company agrees to have an annual audit
made by its regular independent certified public accountants and to furnish the
Trustee (within 30 days after receipt by the Company) with a balance sheet and
statement of income and surplus showing the financial condition of the Company
and its consolidated subsidiaries, if any, at the close of each fiscal year and
the results of operations of the Company and its consolidated subsidiaries, if
any, for each fiscal year, accompanied by a report of said accountants that such
statements have been prepared in accordance with generally accepted accounting
principles. The Company's obligations under this Section 5.2 may be satisfied by
delivering a copy of the Company's Annual Report on Form 10-K to the Trustee
within 10 days after it is filed with the Securities and Exchange Commission.
Delivery of such reports, information and documents to the Trustee is for
informational purposes only and the Trustee's receipt of such shall not
constitute constructive notice of any information contained therein or
determinable from information contained therein, including the Company's
compliance with any of its covenants hereunder (as to which the Trustee is
entitled to rely exclusively on officer's certificates).
SECTION 5.3. RESERVED.
SECTION 5.4. RECORDATION AND OTHER INSTRUMENTS. The Company shall cause
such security agreements, financing statements and all supplements thereto and
other instruments as may be required from time to time to be kept, to be
recorded and filed in such manner and in such places as may be required by law
in order to fully preserve, protect and perfect the security of the Owners of
the Bonds and the rights of the Trustee, and to perfect the security interest
created by the Indenture. The Company agrees to abide by the provisions of
Section 5.11 of the Indenture to the extent applicable to the Company.
SECTION 5.5. NO WARRANTY BY THE ISSUER. The Issuer makes no warranty,
either express or implied, as to the Project.
SECTION 5.6. AGREEMENT AS TO OWNERSHIP OF THE PROJECT. The Issuer and the
Company agree that title to the Project shall not be in the Issuer, and that the
Issuer shall have no interest in the Project.
SECTION 5.7. COMPANY TO FURNISH NOTICE OF RATE PERIOD ADJUSTMENTS;
LIQUIDITY FACILITY REQUIREMENTS; AUCTION RATE PERIOD PROVISIONS. The Company is
hereby granted the
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option to designate from time to time changes in Rate Periods (and to rescind
such changes) in the manner and to the extent set forth in Section 2.03 of the
Indenture. In the event the Company elects to exercise any such option, the
Company agrees that it shall cause notices of adjustments of Rate Periods (or
rescissions thereof) to be given to the Issuer, the Trustee and the Remarketing
Agent in accordance with Section 2.03(a), (b), (c), (d) or (e) of the Indenture,
and a copy of each such notice shall also be given at such time to S&P and
Moody's.
The Company hereby agrees that, so long as the Bonds are insured by a Bond
Insurance Policy issued by the Bond Insurer and notwithstanding the provisions
of Section 2.03 of the Indenture, it shall not give notice of its intention to
adjust the Rate Period for the Bonds to a Daily Rate Period, a Weekly Rate
Period or a Flexible Rate Period until the Company shall provide a liquidity
facility reasonably acceptable to the Bond Insurer from a liquidity facility
provider reasonably acceptable to the Bond Insurer in accordance with the Bond
Insurer's liquidity facility requirements to be effective on the related date of
adjustment.
If during any Auction Rate Period (i) consisting of Auction Periods of 35
days or less, the Bonds shall bear interest at the Maximum Interest Rate for a
period in excess of 180 days, or (ii) consisting of one Auction Period of 180
days or more, the Bonds shall bear interest at the Maximum Interest Rate for
such Period, the Company shall notify the Bond Insurer in writing of such event
and agrees to cooperate with the Bond Insurer to take all steps reasonably
necessary to adjust the Rate Period on the Bonds as soon as reasonably
practicable in accordance with the provisions of the Indenture to the Rate
Period which the Remarketing Agent advises the Company and the Bond Insurer will
be the lowest interest rate (taking into account all relevant costs) which would
enable the Remarketing Agent to sell all the Bonds on the date of such
adjustment at a price equal to 100% of the principal amount thereof (the "Lowest
Interest Rate Period"). If at such time the Company shall be in default under
the Agreement but the Bond Insurer shall not have failed to comply with its
payment obligations under the Bond Insurance Policy, the Bond Insurer may, in
its discretion, direct the Company to provide notice of the adjustment of the
Rate Period on the Bonds to the Lowest Interest Rate Period in accordance with
the provisions of Section 2.03 of the Indenture.
SECTION 5.8. INFORMATION REPORTING, ETC. The Issuer covenants and agrees
that, upon the direction of the Company or Bond Counsel, it will mail or cause
to be mailed to the Secretary of the Treasury (or his designee as prescribed by
regulation, currently the Internal Revenue Service Center, Ogden, Utah) a
statement setting forth the information required by Section 149(e) of the Code,
which statement shall be in the form of the Information Return for Tax-Exempt
Private Activity Bond Issues (Form 8038) of the Internal Revenue Service (or any
successor form) and which shall be completed by the Company and Bond Counsel
based in part upon information supplied by the Company and Bond Counsel.
SECTION 5.9. LIMITED LIABILITY OF ISSUER. Any obligation or liability of
the Issuer created by or arising out of this Agreement or otherwise incurred in
connection with the issuance of the Bonds (including without limitation any
liability created by or arising out of the representations, warranties or
covenants set forth herein or otherwise) shall not impose a debt or pecuniary
liability upon the Issuer or the State or any political subdivision thereof, or
a charge upon the general credit or taxing powers of any of the foregoing, but
shall be payable solely out
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of the Revenues or other amounts payable by the Company to the Issuer hereunder
or otherwise (including without limitation any amounts derived from
indemnifications given by the Company).
Neither the issuance of the Bonds nor the delivery of this Agreement shall,
directly or indirectly or contingently, obligate the Issuer or the State or any
political subdivision thereof to levy any form of taxation therefor or to make
any appropriation for their payment. Nothing in the Bonds or in the Indenture or
this Agreement or the proceedings of the Issuer authorizing the Bonds or in the
Act or in any other related document shall be construed to authorize the Issuer
to create a debt of the Issuer or the State or any political subdivision thereof
within the meaning of any constitutional or statutory provision of the State.
The principal of, and premium, if any, and interest on, the Bonds shall be
payable solely from the funds pledged for their payment in accordance with the
Indenture and available therefor under this Agreement. Neither the State nor any
political subdivision thereof shall in any event be liable for the payment of
the principal of, premium, if any, or interest on, the Bonds or for the
performance of any pledge, obligation or agreement of any kind whatsoever which
may be undertaken by the Issuer. No breach of any such pledge, obligation or
agreement may impose any pecuniary liability upon the Issuer or the State or any
political subdivision thereof, or any charge upon the general credit or against
the taxing power of the Issuer or the State or any political subdivision
thereof.
SECTION 5.10. RESERVED.
SECTION 5.11. INDENTURE COVENANTS. The Company covenants to observe and
perform all of the obligations imposed on it under the Indenture.
ARTICLE VI
EVENTS OF DEFAULT AND REMEDIES
SECTION 6.1. EVENTS OF DEFAULT DEFINED. The following shall be "events of
default" under this Agreement and the terms "event of default" or "default"
shall mean, whenever they are used in this Agreement, any one or more of the
following events:
(a) Failure by the Company to pay when due any amounts required to be
paid under Section 4.2(a) hereof, which failure results in an event of
default under subparagraph (a) or (b) of Section 9.01 of the Indenture; or
(b) Failure by the Company to pay or cause to be paid any payment
required to be paid under Section 4.2(b) hereof, which failure results in
an event of default under subparagraph (c) of Section 9.01 of the
Indenture; or
(c) Failure by the Company to observe and perform any covenant,
condition or agreement on its part to be observed or performed in this
Agreement, other than as referred to in (a) and (b) above, for a period of
90 days after written notice, specifying
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such failure and requesting that it be remedied and stating that such
notice is a "Notice of Default" hereunder, given to the Company by the
Trustee or to the Company and the Trustee by the Issuer, unless the Issuer
and the Trustee shall agree in writing to an extension of such time prior
to its expiration; provided, however, if the failure stated in the notice
cannot be corrected within the applicable period, the Issuer and the
Trustee will not unreasonably withhold their consent to an extension of
such time if corrective action is instituted within the applicable period
and diligently pursued until the failure is corrected and such corrective
action or diligent pursuit is evidenced to the Trustee by a certificate of
an Authorized Company Representative; or
(d) A proceeding or case shall be commenced, without the application
or consent of the Company, in any court of competent jurisdiction seeking
(i) liquidation, reorganization, dissolution, winding-up or composition or
adjustment of debts, (ii) the appointment of a trustee, receiver,
custodian, liquidator or the like of the Company or of all or any
substantial part of its assets, or (iii) similar relief under any law
relating to bankruptcy, insolvency, reorganization, winding-up or
composition or adjustment of debts, and such proceeding or cause shall
continue undismissed, or an order, judgment, or decree approving or
ordering any of the foregoing shall be entered and shall continue in effect
for a period of 90 days; or an order for relief against the Company shall
be entered against the Company in an involuntary case under the Bankruptcy
Code (as now or hereafter in effect) or other applicable law; or
(e) The Company shall admit in writing its inability to pay its debts
generally as they become due or shall file a petition in voluntary
bankruptcy or shall make any general assignment for the benefit of its
creditors, or shall consent to the appointment of a receiver or trustee of
all or substantially all of its property, or shall commence a voluntary
case under the Bankruptcy Code (as now or hereafter in effect), or shall
file in any court of competent jurisdiction a petition seeking to take
advantage of any other law relating to bankruptcy, insolvency,
reorganization, winding-up or composition or adjustment of debts, or shall
fail to controvert in a timely or appropriate manner, or acquiesce in
writing to, any petition filed against it in an involuntary case under such
Bankruptcy Code or other applicable law; or
(f) Dissolution or liquidation of the Company; provided that the term
"dissolution or liquidation of the Company" shall not be construed to
include the cessation of the corporate existence of the Company resulting
either from a merger or consolidation of the Company into or with another
corporation or a dissolution or liquidation of the Company following a
transfer of all or substantially all of its assets as an entirety, under
the conditions permitting such actions contained in Section 5.1 hereof; or
(g) The occurrence of an "event of default" under the Indenture.
The foregoing provisions of Section 6.1(c) are subject to the following
limitations: If by reason of Force Majeure the Company is unable in whole or in
part to carry out its agreements on its part herein contained, other than the
obligations on the part of the Company contained in
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Article IV and Sections 5.3 and 6.4 hereof, the Company shall not be deemed in
default during the continuance of such inability. The Company agrees, however,
to remedy with all reasonable dispatch the cause or causes preventing the
Company from carrying out its agreements; provided that the settlement of
strikes, lockouts and other industrial disturbances shall be entirely within the
discretion of the Company and the Company shall not be required to make
settlement of strikes, lockouts and other industrial disturbances by acceding to
the demands of the opposing party or parties when such course is in the sole
judgment of the Company unfavorable to the Company.
SECTION 6.2. REMEDIES ON DEFAULT. Whenever any event of default referred to
in Section 6.1 hereof shall have happened and be continuing, the Trustee, as
assignee of the Issuer:
(a) shall, by notice in writing to the Company, declare the unpaid
indebtedness under Section 4.2(a) hereof to be due and payable immediately,
if concurrently with or prior to such notice the unpaid principal amount of
the Bonds shall have been declared to be due and payable, and upon any such
declaration the same (being an amount sufficient, together with other
moneys available therefor in the Bond Fund, to pay the unpaid principal of,
premium, if any, and interest accrued on, the Bonds) shall become and shall
be immediately due and payable as liquidated damages; and
(b) may take whatever action at law or in equity as may appear
necessary or desirable to collect the payments and other amounts then due
and thereafter to become due hereunder or to enforce performance and
observance of any obligation, agreement or covenant of the Company under
this Agreement.
Any amounts collected pursuant to action taken under this Section 6.2 shall
be paid into the Bond Fund (unless otherwise provided in this Agreement) and
applied in accordance with the provisions of the Indenture. No action taken
pursuant to this Section 6.2 shall relieve the Company from the Company's
obligations pursuant to Section 4.2 hereof.
No recourse shall be had for any claim based on this Agreement against any
officer, director or stockholder, past, present or future, of the Company as
such, either directly or through the Company, under any constitutional
provision, statute or rule of law, or by the enforcement of any assessment or by
any legal or equitable proceeding or otherwise.
Nothing herein contained shall be construed to prevent the Issuer from
enforcing directly any of its rights under Sections 4.2(e), 4.2(g), 5.3 and 6.4
hereof.
The Company shall promptly notify the Issuer of any action taken by the
Company under the grant of authority from the Issuer under the last paragraph of
Section 9.01 of the Indenture.
SECTION 6.3. NO REMEDY EXCLUSIVE. No remedy herein conferred upon or
reserved to the Issuer is intended to be exclusive of any other available remedy
or remedies, but each and every such remedy shall be cumulative and shall be in
addition to every other remedy given under this Agreement or now or hereafter
existing at law or in equity or by statute. No delay or omission to exercise any
right or power accruing upon any default shall impair any such right or
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power or shall be construed to be a waiver thereof, but any such right and power
may be exercised from time to time and as often as may be deemed expedient. In
order to entitle the Issuer or the Trustee to exercise any remedy reserved to it
in this Article, it shall not be necessary to give any notice, other than such
notice as may be herein expressly required. Subject to the provisions of the
Indenture and hereof, such rights and remedies as are given the Issuer hereunder
shall also extend to the Trustee. The Owners of the Bonds, subject to the
provisions of the Indenture, shall be entitled to the benefit of all covenants
and agreements herein contained.
SECTION 6.4. AGREEMENT TO PAY FEES AND EXPENSES OF COUNSEL. In the event
the Company should default under any of the provisions of this Agreement and the
Issuer or the Trustee should employ Counsel or incur other expenses for the
collection of the indebtedness hereunder or the enforcement of performance or
observance of any obligation or agreement on the part of the Company herein
contained, the Company agrees that it will on written demand therefor pay to the
Trustee or the Issuer (or to the Counsel for either of such parties if directed
by such party), the reasonable fees and expenses of such Counsel and such other
expenses so incurred by or on behalf of the Issuer or the Trustee.
SECTION 6.5. NO ADDITIONAL WAIVER IMPLIED BY ONE WAIVER; CONSENTS TO
WAIVERS. In the event any agreement contained in this Agreement should be
breached by either party and thereafter waived by the other party, such waiver
shall be limited to the particular breach so waived and shall not be deemed to
waive any other breach hereunder. No waiver shall be effective unless in writing
and signed by the party making the waiver. The Issuer shall have no power to
waive any default hereunder by the Company without the consent of the Trustee to
such waiver. The Trustee shall have the power to waive any default by the
Company hereunder, except a default under Section 3.4, 4.2(e), 4.2(g), 5.3 or
6.4 hereof, in so far as it pertains to the Issuer, without the prior written
concurrence of the Issuer. Notwithstanding the foregoing, if, after the
acceleration of the maturity of the outstanding Bonds by the Trustee pursuant to
Section 9.02 of the Indenture, (i) all arrears of principal of and interest on
the outstanding Bonds and interest on overdue principal and (to the extent
permitted by law) on overdue installments of interest at the rate of interest
borne by the Bonds on the date on which such principal or interest became due
and payable and the premium, if any, on all Bonds then Outstanding which have
become due and payable otherwise than by acceleration, and all other sums
payable under the Indenture, except the principal of and the interest on such
Bonds which by such acceleration shall have become due and payable, shall have
been paid, (ii) all other things shall have been performed in respect of which
there was a default, (iii) there shall have been paid the reasonable fees and
expenses of the Trustee and of the Owners of such Bonds, including reasonable
attorneys' fees paid or incurred and (iv) such event of default under the
Indenture shall be waived in accordance with Section 9.09 of the Indenture with
the consequence that such acceleration under Section 9.02 of the Indenture is
rescinded, then the Company's default hereunder shall be deemed to have been
waived and its consequences rescinded and no further action or consent by the
Trustee or the Issuer shall be required; provided that there has been furnished
an opinion of Bond Counsel to the effect that such waiver will not adversely
affect the exemption from federal income taxes of interest on the Bonds.
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ARTICLE VII
OPTIONS AND OBLIGATIONS OF COMPANY;
PREPAYMENTS; REDEMPTION OF BONDS
SECTION 7.1. OPTION TO PREPAY. The Company shall have, and is hereby
granted, the option to prepay the payments due hereunder in whole or in part at
any time or from time to time (a) to provide for the redemption of Bonds
pursuant to the provisions of Section 3.01(A) of the Indenture or (b) to
provide for the defeasance of the Bonds pursuant to Article VIII of the
Indenture. In the event the Company elects to provide for the redemption of
Bonds as permitted by this Section, the Company shall notify and instruct the
Trustee in accordance with Section 7.3 hereof to redeem all or any portion of
the Bonds in advance of maturity. If the Company so elects, any redemption of
Bonds pursuant to Section 3.01(A) of the Indenture may be made conditional.
SECTION 7.2. OBLIGATION TO PREPAY. The Company covenants and agrees that if
all or any part of the Bonds are unconditionally called for redemption in
accordance with the Indenture or become subject to mandatory redemption (except
as otherwise provided in Section 3.02 of the Indenture), it will prepay the
indebtedness hereunder in whole or in part in an amount sufficient to redeem
such Bonds on the date fixed for the redemption of such Bonds.
SECTION 7.3. NOTICE OF PREPAYMENT. Upon the exercise of the option granted
to the Company in Section 7.1 hereof, or upon the Company having knowledge of
the occurrence of any event requiring mandatory redemption of the Bonds in
accordance with Section 3.01(B) of the Indenture, the Company shall give written
notice to the Issuer, the Remarketing Agent, the Auction Agent and the Trustee.
The notice shall provide for the date of the application of the prepayment made
by the Company hereunder to the retirement of the Bonds in whole or in part
pursuant to call for redemption and shall be given by the Company not less than
five Business Days prior to the date notice of such redemption must be given by
the Trustee to the Bondholders as provided in Section 3.02 of the Indenture or
such later date as is acceptable to the Trustee and the Issuer.
ARTICLE VIII
MISCELLANEOUS
SECTION 8.1. NOTICES. (a) Except as otherwise provided herein, all notices,
certificates or other communications hereunder shall be sufficiently given if in
writing and shall be deemed given when mailed by first class mail, postage
prepaid, or by qualified overnight courier service, courier charges prepaid, or
by facsimile (receipt of which is orally confirmed) addressed as follows: if to
the Issuer, at 1001 East Ninth Street, Building A, Room 225, Reno, Nevada 89512,
or to telecopy number (775) 328-2037, Attention: Finance Director; if to the
Company, at 6100 Neil Road, Reno, Nevada 89520, or to telecopy number (702)
227-2250, Attention: Treasurer; if to the Trustee, at 385 Rifle Camp Road, West
Paterson, New Jersey 07424, or to telecopy number (973) 357-7840, Attention:
Corporate Trust Services; if to the Remarketing Agent, at the address set forth
in the Remarketing Agreement, if any; and if to the Auction Agent, at the
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address set forth in the Auction Agreement, if any. In case by reason of the
suspension of regular mail service, it shall be impracticable to give notice by
first class mail of any event to the Issuer, to the Company, to the Remarketing
Agent, to the Auction Agent when such notice is required to be given pursuant to
any provisions of this Agreement, then any manner of giving such notice as shall
be satisfactory to the Trustee shall be deemed to be sufficient giving of such
notice. The Issuer, the Company, the Trustee, the Remarketing Agent and the
Auction Agent may, by notice pursuant to this Section 8.1, designate any
different addresses to which subsequent notices, certificates or other
communications shall be sent.
(b) The Trustee agrees to accept and act upon instructions or
directions pursuant to this Agreement sent by unsecured e-mail, facsimile
transmission or other similar unsecured electronic methods, provided,
however, that (a) the Company and/or Issuer, subsequent to such
transmission of written instructions, shall, upon request by the Trustee,
provide the originally executed instructions or directions to the Trustee,
(b) upon request by the Trustee, such originally executed instructions or
directions shall be signed by a person as may be designated and authorized
to sign for the Company and/or Issuer or in the name of the Company and/or
Issuer, by an authorized representative of the Company and/or Issuer, and
(c) upon the request by the Trustee, the Company and/or Issuer shall
provide to the Trustee an incumbency certificate listing such designated
persons, which incumbency certificate shall be amended whenever a person is
to be added or deleted from the listing. If the Company and/or Issuer
elects to give the Trustee e-mail or facsimile instructions (or
instructions by a similar electronic method) and the Trustee elects to act
upon such instructions, the Trustee's reasonable interpretation and
understanding of such instructions shall be deemed controlling. The Trustee
shall not be liable for any losses, costs or expenses arising directly or
indirectly from the Trustee's reasonable reliance upon and compliance with
such instructions notwithstanding that such instructions conflict or are
inconsistent with a subsequent written instruction.
SECTION 8.2. ASSIGNMENTS. This Agreement may not be assigned by either
party without consent of the other and the Trustee, except that the Issuer shall
assign to the Trustee its rights under this Agreement (except under Sections
4.2(e), 4.2(g), 5.3, and 6.4 hereof) as provided by Section 4.4 hereof, and the
Company may assign its rights under this Agreement to any transferee or any
surviving or resulting corporation as provided by Section 5.1 hereof.
SECTION 8.3. SEVERABILITY. If any provision of this Agreement shall be held
or deemed to be or shall, in fact, be illegal, inoperative or unenforceable, the
same shall not affect any other provision or provisions herein contained or
render the same invalid, inoperative, or unenforceable to any extent whatever.
SECTION 8.4. EXECUTION OF COUNTERPARTS. This Agreement may be
simultaneously executed in several counterparts, each of which shall be an
original and all of which shall constitute but one and the same instrument.
SECTION 8.5. AMOUNTS REMAINING IN BOND FUND. It is agreed by the parties
hereto that after payment in full of (i) the Bonds (or provision for payment
thereof having been made in accordance with the provisions of the Indenture),
(ii) the fees, charges and expenses of the Trustee in accordance with the
Indenture, (iii) the Administrative Expenses, (iv) the fees and
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expenses of the Remarketing Agent, the Auction Agent and the Issuer and (v) all
other amounts required to be paid under this Agreement and the Indenture, any
amounts remaining in the Bond Fund shall belong to and be paid to the Company by
the Trustee.
SECTION 8.6. AMENDMENTS, CHANGES AND MODIFICATIONS. This Agreement may be
amended, changed, modified, altered or terminated only by written instrument
executed by the Issuer and the Company, and only if the written consent of the
Trustee thereto is obtained, and only in accordance with the provisions of
Article XII of the Indenture.
SECTION 8.7. GOVERNING LAW. This Agreement shall be governed exclusively by
and construed in accordance with the applicable laws of the State.
SECTION 8.8. AUTHORIZED ISSUER AND COMPANY REPRESENTATIVES. Whenever under
the provisions of this Agreement the approval of the Issuer or the Company is
required to take some action at the request of the other, such approval of such
request shall be given for the Issuer by the Authorized Issuer Representative
and for the Company by the Authorized Company Representative, and the other
party hereto and the Trustee shall be authorized to act on any such approval or
request and neither party hereto shall have any complaint against the other or
against the Trustee as a result of any such action taken.
SECTION 8.9. TERM OF THE AGREEMENT. This Agreement shall be in full force
and effect from its date to and including such date as all of the Bonds issued
under the Indenture shall have been fully paid or retired (or provision for such
payment shall have been made as provided in the Indenture), provided that all
representations and certifications by the Company as to all matters affecting
the tax-exempt status of the Bonds and the covenants of the Company in Sections
4.2(c), 4.2(d), 4.2(e), 4.2(f) and 4.2(g) hereof shall survive the termination
of this Agreement.
SECTION 8.10. CANCELLATION AT EXPIRATION OF TERM. At the acceleration,
termination or expiration of the term of this Agreement and following full
payment of the Bonds or provision for payment thereof and of all other fees and
charges having been made in accordance with the provisions of this Agreement and
the Indenture, the Issuer shall deliver to the Company any documents and take or
cause the Trustee to take such actions as may be necessary to effectuate the
cancellation and evidence the termination of this Agreement.
SECTION 8.11. BOND INSURANCE. The payment of the principal of and interest
on the Bonds when due is to be insured under, and to the extent provided in, the
Bond Insurance Policy, including the endorsements thereto, to be issued by the
Bond Insurer, and the Issuer and the Company agree to be bound by the provisions
contained in Appendix C to the Indenture and the Company agrees to be bound by
the provisions contained in the Insurance Agreement. In the event of any
conflict between the provisions of Appendix C to the Indenture and the
provisions of this Agreement, the provisions of Appendix C shall govern and
control.
All references in this Agreement to the Bond Insurer shall only apply so
long as a Bond Insurance Policy issued by the Bond Insurer is in effect for any
of the Bonds (and the Bond Insurer has not failed to comply with its payment
obligations under the Bond Insurance Policy).
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IN WITNESS WHEREOF, the Issuer and the Company have caused this Agreement
to be executed in their respective corporate names and their respective
corporate seals to be hereunto affixed and attested by their duly authorized
officers, all as of the date first above written.
WASHOE COUNTY, NEVADA
By
Chairman
Board of County Commissioners
(SEAL)
Attest:
County Clerk
SIERRA PACIFIC POWER COMPANY
By
Treasurer
(SEAL)
Attest:
Secretary
IN WITNESS WHEREOF, the Issuer and the Company have caused this Agreement
to be executed in their respective corporate names and their respective
corporate seals to be hereunto affixed and attested by their duly authorized
officers, all as of the date first above written.
WASHOE COUNTY, NEVADA
By
Chairman
Board of County Commissioners
(SEAL)
Attest:
County Clerk
SIERRA PACIFIC POWER COMPANY
By
Vice President, Finance and Risk, and
Treasurer
(SEAL)
Attest:
Secretary
Exhibit 10(E)
FINANCING AGREEMENT
Dated as of November 1, 2006
By and Between
WASHOE COUNTY, NEVADA
and
SIERRA PACIFIC POWER COMPANY
RELATING TO
GAS AND WATER FACILITIES REFUNDING REVENUE BONDS
(SIERRA PACIFIC POWER COMPANY PROJECT)
SERIES 2006C
The amounts payable to the Issuer (except for amounts payable to, and
certain rights and privileges of, the Issuer under Sections 4.2(e), 4.2(g), 5.3
and 6.4 hereof and any rights of the Issuer to receive any notices,
certificates, requests, requisitions or communications hereunder) and certain
other rights of the Issuer under this Financing Agreement have been pledged and
assigned under the Indenture of Trust dated as of November 1, 2006, between the
Issuer and The Bank of New York, as Trustee.
FINANCING AGREEMENT
TABLE OF CONTENTS
(This Table of Contents is not a part of this Agreement
and is only for convenience of reference).
SECTION HEADING PAGE
------- ------- ----
ARTICLE I DEFINITIONS............................................. 1
ARTICLE II REPRESENTATIONS......................................... 6
Section 2.1. Representations and Covenants by the Issuer............. 6
Section 2.2. Representations by the Company.......................... 6
ARTICLE III ISSUANCE OF THE BONDS................................... 7
Section 3.1. Agreement to Issue Bonds; Application of Bond Proceeds.. 7
Section 3.2. Deposit of Additional Funds by Company; Redemption of
Prior Bonds.......................................... 7
Section 3.3. Investment of Moneys in the Bond Fund and the Prior
Bonds Redemption Fund................................ 7
Section 3.4. Tax Exempt Status of Bonds.............................. 8
ARTICLE IV LOAN AND PROVISIONS FOR REPAYMENT....................... 9
Section 4.1. Loan of Bond Proceeds................................... 9
Section 4.2. Loan Repayments and Other Amounts Payable............... 9
Section 4.3. No Defense or Set-Off................................... 11
Section 4.4. Payments Pledged and Assigned........................... 11
Section 4.5. Payment of the Bonds and Other Amounts.................. 11
ARTICLE V SPECIAL COVENANTS AND AGREEMENTS........................ 12
Section 5.1. Company to Maintain its Corporate Existence; Conditions
Under Which Exceptions Permitted..................... 12
Section 5.2. Annual Statement........................................ 13
Section 5.3. Maintenance and Repair; Insurance; Taxes; Disposition... 13
Section 5.4. Recordation and Other Instruments....................... 14
Section 5.5. No Warranty by the Issuer............................... 14
Section 5.6. Agreement as to Ownership of the Project................ 14
Section 5.7. Company to Furnish Notice of Rate Period Adjustments;
Liquidity Facility Requirements; Auction Rate Period
Provisions........................................... 14
Section 5.8. Information Reporting, Etc.............................. 15
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Section 5.9. Limited Liability of Issuer............................. 15
Section 5.10. Inspection of Project................................... 16
Section 5.11. Indenture Covenants..................................... 16
ARTICLE VI EVENTS OF DEFAULT AND REMEDIES.......................... 16
Section 6.1. Events of Default Defined............................... 16
Section 6.2. Remedies on Default..................................... 17
Section 6.3. No Remedy Exclusive..................................... 18
Section 6.4. Agreement to Pay Fees and Expenses of Counsel........... 18
Section 6.5. No Additional Waiver Implied by One Waiver; Consents to
Waivers.............................................. 19
ARTICLE VII OPTIONS AND OBLIGATIONS OF COMPANY; PREPAYMENTS;
REDEMPTION OF BONDS.................................. 19
Section 7.1. Option to Prepay........................................ 19
Section 7.2. Obligation to Prepay.................................... 19
Section 7.3. Notice of Prepayment.................................... 20
ARTICLE VIII MISCELLANEOUS........................................... 20
Section 8.1. Notices................................................. 20
Section 8.2. Assignments............................................. 21
Section 8.3. Severability............................................ 21
Section 8.4. Execution of Counterparts............................... 21
Section 8.5. Amounts Remaining in Bond Fund.......................... 21
Section 8.6. Amendments, Changes and Modifications................... 21
Section 8.7. Governing Law........................................... 21
Section 8.8. Authorized Issuer and Company Representatives........... 21
Section 8.9. Term of the Agreement................................... 22
Section 8.10. Cancellation at Expiration of Term...................... 22
Section 8.11. Bond Insurance.......................................... 22
Signature................................................................ 23
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THIS FINANCING AGREEMENT made and entered into as of November 1, 2006, by
and between WASHOE COUNTY, NEVADA, a political subdivision of the State of
Nevada, party of the first part (hereinafter referred to as the "Issuer"), and
SIERRA PACIFIC POWER COMPANY, a corporation duly organized and existing under
the laws of the State of Nevada, party of the second part (hereinafter referred
to as the "Company"),
WITNESSETH:
In consideration of the respective representations and agreements
hereinafter contained, the parties hereto agree as follows (provided, that in
the performance of the agreements of the Issuer herein contained, any obligation
it may thereby incur shall not constitute or give rise to a pecuniary liability
or a charge upon its general credit or against its taxing powers but shall be
payable solely out of the Revenues (as hereinafter defined) derived from this
Financing Agreement and the Bonds, as hereinafter defined):
ARTICLE I
DEFINITIONS
The following terms shall have the meanings specified in this Article
unless the context clearly requires otherwise. The singular shall include the
plural and the masculine shall include the feminine.
"Act" means the County Economic Development Revenue Bond Law, as amended,
contained in Sections 244A.669 to 244A.763, inclusive, of the Nevada Revised
Statutes.
"Administrative Expenses" means the reasonable and necessary expenses
(including the reasonable value of employee services and fees of Counsel)
incurred by the Issuer in connection with the Bonds, this Agreement, the
Indenture and any transaction or event contemplated by this Agreement or the
Indenture.
"Agreement" means this Financing Agreement by and between the Issuer and
the Company, as from time to time amended and supplemented.
"Auction Agent" means the auction agent appointed in accordance with the
provisions of the Indenture.
"Authorized Company Representative" means any person who, at the time,
shall have been designated to act on behalf of the Company by a written
certificate furnished to the Issuer, the Remarketing Agent and the Trustee
containing the specimen signature of such person and signed on behalf of the
Company by any officer of the Company. Such certificate may designate an
alternate or alternates.
"Authorized Issuer Representative" means any person at the time designated
to act on behalf of the Issuer by a written certificate furnished to the Company
and the Trustee containing the specimen signature of such person and signed on
behalf of the Issuer by its Chairman. Such certificate may designate an
alternate or alternates.
"Bankruptcy Code" means the United States Bankruptcy Reform Act of 1978, as
amended from time to time, or any substitute or replacement legislation.
"Bond" or "Bonds" means the Issuer's bonds identified in Section 2.02 of
the Indenture.
"Bond Counsel" means the Counsel who renders the opinion as to the
tax-exempt status of interest on the Bonds or other nationally recognized
municipal bond counsel mutually acceptable to the Issuer and the Company.
"Bond Fund" means the fund created by Section 6.02 of the Indenture.
"Code" means the United States Internal Revenue Code of 1986, as amended,
and regulations promulgated or proposed thereunder and, to the extent applicable
to the Bonds or the Prior Bonds, the 1954 Code.
"Company" means Sierra Pacific Power Company, a Nevada corporation, and its
successors and assigns and any surviving, resulting or transferee corporation as
permitted in Section 5.1 hereof.
"Counsel" means an attorney at law or a firm of attorneys (who may be an
employee of or counsel to the Issuer or the Company or the Trustee) duly
admitted to the practice of law before the highest court of any state of the
United States of America or of the District of Columbia.
"Delivery Agreement" means the Delivery Agreement dated the Dated Date,
between the Company and the Trustee, as amended, supplemented or restated from
time to time, pursuant to which the Company will issue to the Trustee the G&R
Notes at the time of the initial authentication and delivery of the Bonds.
"Extraordinary Services" and "Extraordinary Expenses" means all services
rendered and all expenses (including fees and expenses of Counsel) incurred
under the Indenture and the Tax Agreement other than Ordinary Services and
Ordinary Expenses.
"Force Majeure" means acts of God, strikes, lockouts or other industrial
disturbances; acts of public enemies; orders or restraints of any kind of the
governments of the United States or of the State, or any of their departments,
agencies or officials, or any civil or military authority; insurrections; riots;
landslides; lightning; earthquakes; fires; tornadoes; volcanoes; storms;
droughts; floods; explosions, breakage, or malfunction or accident to machinery,
transmission lines, pipes or canals, even if resulting from negligence; civil
disturbances; or any other cause not reasonably within the control of the
Company.
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"G&R Indenture" means the General and Refunding Mortgage Indenture dated as
of May 1, 2001 between the Company and the G&R Trustee, as amended and
supplemented.
"G&R Notes" means the Company's $49,750,000 General and Refunding Mortgage
Note, Series N, No. N-4, due March 1, 2036.
"G&R Trustee" means The Bank of New York, as trustee under the G&R
Indenture or any successor trustee.
"Governing Body" means the Board of County Commissioners of the Issuer.
"Hereof," "herein," "hereunder" and other words of similar import refer to
this Agreement as a whole.
"Indenture" means the Indenture of Trust relating to this Agreement between
the Issuer and The Bank of New York, as Trustee, of even date herewith, pursuant
to which the Bonds are authorized to be issued, including any indentures
supplemental thereto or amendatory thereof.
"Issuer" means Washoe County, Nevada, and any successor body to the duties
or functions of the Issuer.
"1954 Code" means the Internal Revenue Code of 1954, as amended, and the
applicable regulations thereunder.
"Ordinary Services" and "Ordinary Expenses" means those services normally
rendered and those expenses including fees and expenses of Counsel, normally
incurred by a trustee or paying agent under instruments similar to the Indenture
and the Tax Agreement.
"Owner" or "owner of Bonds" means the Person or Persons in whose name or
names a Bond shall be registered on books of the Issuer kept by the Registrar
for that purpose in accordance with the terms of the Indenture.
"Person" means natural persons, firms, partnerships, associations,
corporations, trusts and public bodies.
"Prior Bonds" means the Series 1987 Bonds, the Series 1993A Bonds and the
Series 1993B Bonds.
"Prior Bond Funds" means the Series 1987 Bond Fund, the Series 1993A Bond
Fund and the Series 1993B Bond Fund.
"Prior Indentures" means the Series 1987 Indenture, the Series 1993A
Indenture and the Series 1993B Indenture.
"Prior Trustees" means the Series 1987 Trustee, the Series 1993A Trustee
and the Series 1993B Trustee.
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"Project" means the Project as defined in the Project Certificate.
"Project Certificate" means the Company's Project and Refunding
Certificate, delivered concurrently with the issuance of the Bonds, with respect
to certain facts which are within the knowledge of the Company and certain
reasonable assumptions of the Company, to enable Chapman and Cutler LLP, as Bond
Counsel, to determine that interest on the Bonds is not includable in the gross
income of the Owners of the Bonds for federal income tax purposes.
"Rebate Fund" means the Rebate Fund, if any, created and established
pursuant to the Tax Agreement.
"Regulated Utility Company" means a corporation (or a limited liability
company) engaged in the distribution of electricity, gas and/or water and which
is regulated by the public utility commission where its primary distribution
business is located.
"Remarketing Agent" means the remarketing agent, if any, appointed in
accordance with Section 4.08 of the Indenture and any permitted successor
thereto.
"Reorganization" means any reorganization, consolidation or merger of the
Company or its affiliates, or any transfer or lease of a substantial portion of
the assets of the Company or its affiliates, as a result of which the obligor
under the Agreement or the obligor on the G&R Notes ceases to be a Regulated
Utility Company.
"Series 1987 Bond Fund" means the fund established pursuant to Section 502
of the Series 1987 Indenture.
"Series 1987 Bonds" means the Issuer's Variable Rate Demand Gas and Water
Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series
1987, currently outstanding in the aggregate principal amount of $45,000,000.
"Series 1987 Indenture" means the Indenture of Trust dated March 1, 1987
between the Issuer and the Series 1987 Trustee, as trustee, pursuant to which
the Series 1987 Bonds were issued.
"Series 1987 Trustee" means The Bank of New York Trust Company, N.A., as
current trustee under the Series 1987 Indenture.
"Series 1993A Bond Fund" means the fund established pursuant to Section
5.02 of the Series 1993A Indenture.
"Series 1993A Bonds" means the Issuer's Water Facilities Refunding Revenue
Bonds (Sierra Pacific Power Company Project) Series 1993A, currently outstanding
in the aggregate principal amount of $9,800,000.
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"Series 1993A Indenture" means the Indenture of Trust dated June 1, 1993
between the Issuer and the Series 1993A Trustee, as trustee, pursuant to which
the Series 1993A Bonds were issued.
"Series 1993A Trustee" means The Bank of New York, as current trustee under
the Series 1993A Indenture.
"Series 1993B Bond Fund" means the fund established pursuant to Section
5.02 of the Series 1993B Indenture.
"Series 1993B Bonds" means the Issuer's Gas and Water Facilities Refunding
Revenue Bonds (Sierra Pacific Power Company Project) Series 1993B, currently
outstanding in the aggregate principal amount of $30,000,000.
"Series 1993B Indenture" means the Indenture of Trust dated June 1, 1993
between the Issuer and the Series 1993B Trustee, as trustee, pursuant to which
the Series 1993 Bonds were issued.
"Series 1993B Trustee" means The Bank of New York, as current trustee under
the Series 1993B Indenture.
"State" means the State of Nevada.
"Tax Agreement" means the Tax Exemption Certificate and Agreement with
respect to the Bonds, dated the date of delivery of the Bonds, among the
Company, the Issuer and the Trustee, as from time to time amended and
supplemented.
"Trust Estate" means the property conveyed to the Trustee pursuant to the
Granting Clauses of the Indenture.
"Trustee" means The Bank of New York, as Trustee under the Indenture, and
any successor Trustee appointed pursuant to Section 10.06 or 10.09 of the
Indenture at the time serving as Trustee thereunder, and any separate or
co-trustee serving as such thereunder.
"Water Project" means the facilities now owned by Truckee Meadows Water
Authority which constitute a portion of the Project, as more fully described in
the Project Certificate.
All other terms used herein which are defined in the Indenture shall have
the same meanings assigned them in the Indenture unless the context otherwise
requires.
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ARTICLE II
REPRESENTATIONS
SECTION 2.1. REPRESENTATIONS AND COVENANTS BY THE ISSUER. The Issuer makes
the following representations and covenants as the basis for the undertakings on
its part herein contained:
(a) The Issuer is a duly organized and existing political subdivision
of the State of Nevada. Under the provisions of the Act, the Issuer is
authorized to enter into the transactions contemplated by this Agreement,
the Indenture and the Tax Agreement and to carry out its obligations
hereunder and thereunder. The Issuer has duly authorized the execution and
delivery of this Agreement, the Indenture and the Tax Agreement.
(b) The Bonds are to be issued under and secured by the Indenture,
pursuant to which certain of the Issuer's interests in this Agreement and
the Revenues derived by the Issuer pursuant to this Agreement will be
pledged and assigned as security for payment of the principal of, premium,
if any, and interest on, the Bonds.
(c) The Governing Body of the Issuer has found that the issuance of
the Bonds will further the public purposes of the Act.
(d) The Issuer has not assigned and will not assign any of its
interests in this Agreement other than pursuant to the Indenture.
(e) No member of the Governing Body of the Issuer, nor any other
officer of the Issuer, has any interest, financial (other than ownership of
less than one-tenth of one percent (.1%) of the publicly traded securities
issued by the Company or its affiliated corporations), employment or other,
in the Company or in the transactions contemplated hereby.
SECTION 2.2. REPRESENTATIONS BY THE COMPANY. The Company makes the
following representations as the basis for the undertakings on its part herein
contained:
(a) The Company is a corporation duly incorporated under the laws of
the State and is in good standing in the State, is qualified to do business
as a foreign corporation in all other states and jurisdictions wherein the
nature of the business transacted by the Company or the nature of the
property owned or leased by it makes such licensing or qualification
necessary, and has the power to enter into and by proper corporate action
has been duly authorized to execute and deliver this Agreement and the Tax
Agreement.
(b) Neither the execution and delivery of this Agreement or the Tax
Agreement, the consummation of the transactions contemplated hereby and
thereby, nor the fulfillment of or compliance with the terms and conditions
of this Agreement and the Tax Agreement, conflicts with or results in a
breach of any of the terms, conditions or
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provisions of any corporate restriction or any agreement or instrument to
which the Company is now a party or by which it is bound, or constitutes a
default under any of the foregoing, or results in the creation or
imposition of any lien, charge or encumbrance whatsoever upon any of the
property or assets of the Company under the terms of any instrument or
agreement other than the Indenture.
(c) The statements, information and descriptions contained in the
Project Certificate and the Tax Agreement, as of the date hereof and at the
time of the delivery of the Bonds to the Underwriter, are and will be true,
correct and complete, do not and will not contain any untrue statement or
misleading statement of a material fact, and do not and will not omit to
state a material fact required to be stated therein or necessary to make
the statements, information and descriptions contained therein, in the
light of the circumstances under which they were made, not misleading.
ARTICLE III
ISSUANCE OF THE BONDS
SECTION 3.1. AGREEMENT TO ISSUE BONDS; APPLICATION OF BOND PROCEEDS. In
order to provide funds to lend to the Company to refund the Prior Bonds as
provided in Section 4.1 hereof, the Issuer agrees that it will issue under the
Indenture, sell and cause to be delivered to the Underwriter, its Bonds in the
aggregate principal amount of $84,800,000, bearing interest and maturing as set
forth in the Indenture. The Issuer will thereupon deposit the proceeds received
from the sale of the Bonds as follows: (1) in the Bond Fund, a sum equal to the
accrued interest, if any, paid by the Underwriter; and (2) $84,800,000 in the
Prior Bonds Redemption Fund to be remitted by the Trustee to the Prior Trustees
for deposit in the Prior Bond Funds to be used to pay to the owners thereof the
principal of the Prior Bonds upon redemption thereof.
SECTION 3.2. DEPOSIT OF ADDITIONAL FUNDS BY COMPANY; REDEMPTION OF PRIOR
BONDS. The Company covenants that such additional amounts as may be required to
redeem the Prior Bonds in accordance with Section 3.1 hereof will be timely
deposited with the Prior Trustee pursuant to the Prior Indentures for such
purpose. Income derived from the investment of the proceeds of the Bonds
deposited in the several accounts of the Prior Bonds Redemption Fund will be
used, to the extent available, to satisfy the obligations of the Company
specified in this Section 3.2. The Company covenants that it will cause the
Prior Bonds to be redeemed within 90 days after the issuance and delivery of the
Bonds.
SECTION 3.3. INVESTMENT OF MONEYS IN THE BOND FUND AND THE PRIOR BONDS
REDEMPTION FUND. Except as otherwise herein provided, any moneys held as a part
of the Bond Fund and the Prior Bonds Redemption Fund shall be invested or
reinvested by the Trustee at the specific written direction of an Authorized
Company Representative as to specific investments, to the extent permitted by
law, in:
(a) bonds or other obligations of the United States of America;
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(b) bonds or other obligations, the payment of the principal of and
interest on which is unconditionally guaranteed by the United States of
America;
(c) obligations issued or guaranteed as to principal and interest by
any agency or person controlled or supervised by and acting as an
instrumentality of the United States of America pursuant to authority
granted by the Congress of the United States of America;
(d) obligations issued or guaranteed by any state of the United States
of America, or any political subdivision of any such state, or in funds
consisting of such obligations to the extent described in Section
1.148-8(e)(3)(iii) of the 1992 Treasury Regulations;
(e) prime commercial paper;
(f) prime finance company paper;
(g) bankers' acceptances drawn on and accepted by commercial banks;
(h) repurchase agreements fully secured by obligations issued or
guaranteed as to principal and interest by the United States of America or
by any person controlled or supervised by and acting as an instrumentality
of the United States of America pursuant to authority granted by the
Congress of the United States of America;
(i) certificates of deposit issued by commercial banks, including
banks domiciled outside of the United States of America; and
(j) units of taxable government money market portfolios composed of
obligations guaranteed as to principal and interest by the United States of
America or repurchase agreements fully collateralized by such obligations.
The investments so purchased shall be held by the Trustee and shall be
deemed at all times a part of the fund and the accounts therein, if any, for
which they were made and the interest accruing thereon and any profit realized
therefrom shall be credited to such fund and the accounts therein, if any,
subject to the provisions of the Tax Agreement. The Company agrees that to the
extent any moneys in the Bond Fund represent moneys held for the payment of
particular Bonds, or to the extent that any moneys are held for the payment of
the purchase price of Bonds pursuant to Article IV of the Indenture, such moneys
shall not be invested.
SECTION 3.4. TAX EXEMPT STATUS OF BONDS. The Company covenants and agrees
that it has not taken or permitted and will not take or permit any action which
results in interest paid on the Bonds being included in gross income of the
holders or beneficial owners of the Bonds for purposes of federal income
taxation (other than a holder or beneficial owner who is a "substantial user" of
the Project or a "related person" within the meaning of Section 103(b)(13) of
the 1954 Code). The Company covenants that none of the proceeds of the Bonds or
the payments to be made under this Agreement, or any other funds which may be
deemed to be
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proceeds of the Bonds pursuant to Section 148(a) of the Code, will be invested
or used in such a way, and that no actions will be taken or not taken, as to
cause the Bonds to be treated as "arbitrage bonds" within the meaning of Section
148(a) of the Code. Without limiting the generality of the foregoing, the
Company covenants and agrees that it will comply with the provisions of the Tax
Agreement and the Project Certificate.
For purposes of the immediately preceding paragraph, the Company will be
deemed to have taken or permitted or omitted to take any action which is taken
or permitted or omitted by Truckee Meadows Water Authority, the owner of the
Water Project, or any subsequent owner or operator of the Water Project or
portion thereof. The Company has received a certificate dated the Dated Date
from Truckee Meadows Water Authority with respect to the Water Project. This
certificate is attached to the Project Certificate.
ARTICLE IV
LOAN AND PROVISIONS FOR REPAYMENT
SECTION 4.1. LOAN OF BOND PROCEEDS. (a) The Issuer agrees, upon the terms
and conditions in this Agreement, to lend to the Company the proceeds (exclusive
of accrued interest, if any) received by the Issuer from the sale of the Bonds
in order to refund the Prior Bonds, and the Company agrees to apply the gross
proceeds of such loan to the refunding of the Prior Bonds as set forth in
Sections 3.1 and 3.2 hereof.
(b) The Issuer and the Company expressly reserve the right to enter
into, to the extent permitted by law, an agreement or agreements other than
this Agreement, with respect to the issuance by the Issuer, under an
indenture or indentures other than the Indenture, of obligations to provide
additional funds to refund all or any principal amount of the Bonds.
SECTION 4.2. LOAN REPAYMENTS AND OTHER AMOUNTS PAYABLE. (a) On each date
provided in or pursuant to the Indenture for the payment (whether at maturity or
upon redemption or acceleration) of principal of, and premium, if any, and
interest on, the Bonds, until the principal of, and premium, if any, and
interest on, the Bonds shall have been fully paid or provision for the payment
thereof shall have been made in accordance with the Indenture, the Company shall
pay to the Trustee in immediately available funds, for deposit in the Bond Fund,
as a repayment installment of the loan of the proceeds of the Bonds pursuant to
Section 4.1(a) hereof, a sum equal to the amount payable on such date (whether
at maturity or upon redemption or acceleration) as principal of, and premium, if
any, and interest on, the Bonds as provided in the Indenture; provided, however,
that the obligation of the Company to make any such repayment installment shall
be reduced by the amount of any moneys then on deposit in the Bond Fund and
available for such payment; and provided further, that the obligation of the
Company to make any such payment shall be deemed to be satisfied and discharged
to the extent provided for under a liquidity facility (if applicable) or under
the G&R Notes.
(b) The Company shall pay to the Trustee amounts equal to the amounts
to be paid by the Trustee for the purchase of Bonds pursuant to Article IV
of the Indenture. Such amounts shall be paid by the Company to the Trustee
in immediately available funds on the date such
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payments pursuant to Section 4.05 of the Indenture are to be made;
provided, however, that the obligation of the Company to make any such
payment shall be deemed to be satisfied and discharged to the extent moneys
are available from the source described in clause (i) of Section 4.05(a) of
the Indenture and to the extent moneys are available under any liquidity
facility (if applicable).
(c) The Company agrees to pay to the Trustee (i) the fees of the
Trustee for the Ordinary Services rendered by it and an amount equal to the
Ordinary Expenses incurred by it under the Indenture and the Tax Agreement,
as and when the same become due, and (ii) the reasonable fees, charges and
expenses of the Trustee for reasonable Extraordinary Services and
Extraordinary Expenses, as and when the same become due, incurred under the
Indenture and the Tax Agreement. The Company agrees that the Trustee, its
officers, agents, servants and employees, shall not be liable for, and
agrees that it will at all times indemnify and hold harmless the Trustee,
its officers, agents, servants and employees against, and pay all expenses
of the Trustee, its officers, agents, servants and employees, relating to
any lawsuit, proceeding or claim and resulting from any action or omission
taken or made by or on behalf of the Trustee, its officers, agents,
servants and employees pursuant to this Agreement, the Indenture or the Tax
Agreement, that may be occasioned by any cause (other than the negligence
or willful misconduct of the Trustee, its officers, agents, servants and
employees). In case any action shall be brought against the Trustee in
respect of which indemnity may be sought against the Company, the Trustee
shall promptly notify the Company in writing and the Company shall be
entitled to assume control of the defense thereof, including the employment
of Counsel reasonably satisfactory to the Trustee and the payment of all
expenses. The Trustee shall have the right to employ separate Counsel in
any such action and participate in the defense thereof, but the fees and
expenses of such Counsel shall be paid by the Trustee unless (i) the
employment of such Counsel has been authorized by the Company, (ii) the
Trustee has determined (which determination may be based upon an opinion of
counsel delivered to the Trustee and furnished to the Company) that there
may be a conflict of interest of such Counsel retained by the Company
between the Company and the Trustee in the conduct of such defense, (iii)
the Company ceases or terminates the employment of such Counsel retained by
the Company or (iv) such Counsel retained by the Company withdraws with
respect to such defense. The Company shall not be liable for any settlement
of any such action without its consent, but if any such action is settled
with the consent of the Company or if there be final judgment for the
plaintiff in any such action, the Company agrees to indemnify and hold
harmless the Trustee from and against any loss or liability by reason of
such settlement or final judgment. The Company agrees that the
indemnification provided herein shall survive the termination of this
Agreement or the Indenture or the resignation of the Trustee. For purposes
of this Section 4.2(c), the Trustee is deemed a third party beneficiary of
this Agreement.
(d) The Company agrees to pay all costs incurred in connection with
the issuance of the Bonds from sources other than Bond proceeds and the
Issuer shall have no obligation with respect to such costs.
(e) The Company agrees to indemnify and hold harmless the Issuer and
any member, officer, official or employee of the Issuer against any and all
losses, costs, charges, expenses, judgments and liabilities created by or
arising out of this Agreement, the Indenture, the
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Remarketing Agreement, the Auction Agreement, the Bond Purchase Agreement,
any Broker-Dealer Agreement or the Tax Agreement or otherwise incurred in
connection with the issuance of the Bonds. The Company agrees to pay the
Issuer its Closing Fee in connection with the issuance of the Bonds in the
amount of $50,000. The Issuer may submit to the Company periodic
statements, not more frequently than monthly, for its Administrative
Expenses and the Company shall make payment to the Issuer of the full
amount of each such statement within 30 days after the Company receives
such statement.
(f) The Company agrees to pay (i) to the Remarketing Agent the
reasonable fees, charges and expenses of such Remarketing Agent and (ii) to
the Auction Agent the reasonable fees, charges and expenses of such Auction
Agent, and the Issuer shall have no obligation or liability with respect to
the payment of any such fees, charges or expenses.
(g) In the event the Company shall fail to make any of the payments
required by (a) or (b) of this Section 4.2, the payment so in default shall
continue as an obligation of the Company until the amount in default shall
have been fully paid and the Company will pay interest to the extent
permitted by law, on any overdue amount at the rate of interest borne by
the Bonds on the date on which such amount became due and payable until
paid. In the event that the Company shall fail to make any of the payments
required by (c), (d), (e) or (f) of this Section 4.2, the payment so in
default shall continue as an obligation of the Company until the amount in
default shall have been fully paid, and the Company agrees to pay the same
with interest thereon to the extent permitted by law at a rate 1% above the
rate of interest then charged by the Trustee on 90- day commercial loans to
its prime commercial borrowers until paid.
SECTION 4.3. NO DEFENSE OR SET-OFF. The obligation of the Company to make
the payments pursuant to this Agreement shall be absolute and unconditional
without defense or set-off by reason of any default by the Issuer under this
Agreement or under any other agreement between the Company and the Issuer or for
any other reason, it being the intention of the parties that the payments
required hereunder will be paid in full when due without any delay or diminution
whatsoever.
SECTION 4.4. PAYMENTS PLEDGED AND ASSIGNED. It is understood and agreed
that all payments required to be made by the Company pursuant to Section 4.2
hereof (except payments made to the Trustee pursuant to Section 4.2(c) hereof,
to the Remarketing Agent and the Auction Agent pursuant to Section 4.2(f)
hereof, to the Issuer pursuant to Section 4.2(e) hereof and to any or all the
Issuer and the Trustee and the Remarketing Agent pursuant to Section 4.2(g)
hereof) and certain rights of the Issuer hereunder are pledged and assigned by
the Indenture. The Company consents to such pledge and assignment. The Issuer
hereby directs the Company and the Company hereby agrees to pay or cause to be
paid to the Trustee all said amounts except payments to be made to the
Remarketing Agent and the Auction Agent pursuant to Section 4.2(f) hereof and
payments to be made to the Issuer pursuant to Sections 4.2(e) and (g) hereof.
The Project will not constitute any part of the security for the Bonds, except
to the extent that the Trustee as holder of G&R Notes has a lien on property
under the G&R Indenture.
SECTION 4.5. PAYMENT OF THE BONDS AND OTHER AMOUNTS. The Bonds and interest
and premium, if any, thereon shall be payable solely from (i) payments made by
the Company to the
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Trustee under Section 4.2(a) hereof and (ii) other moneys on deposit in the Bond
Fund and available therefor.
Payments of principal of, and premium, if any, or interest on, the Bonds
with moneys in the Bond Fund constituting proceeds from the sale of the Bonds or
earnings on investments made under the provisions of the Indenture shall be
credited against the obligation to pay required by Section 4.2(a) hereof.
Whenever any Bonds are redeemable in whole or in part at the option of the
Company, the Trustee, on behalf of the Issuer, shall redeem the same upon the
request of the Company and such redemption (unless conditional) shall be made
from payments made by the Company to the Trustee under Section 4.2(a) hereof
equal to the redemption price of such Bonds.
Whenever payment or provision therefor has been made in respect of the
principal of, or premium, if any, or interest on, all or any portion of the
Bonds in accordance with the Indenture (whether at maturity or upon redemption
or acceleration or upon provision for payment in accordance with Article VIII of
the Indenture), payments shall be deemed paid to the extent such payment or
provision therefor has been made and is considered to be a payment of principal
of, or premium, if any, or interest on, such Bonds. If such Bonds are thereby
deemed paid in full, the Trustee shall notify the Company and the Issuer that
such payment requirement has been satisfied. Subject to the foregoing, or unless
the Company is entitled to a credit under this Agreement or the Indenture, all
payments shall be in the full amount required by Section 4.2(a) hereof.
ARTICLE V
SPECIAL COVENANTS AND AGREEMENTS
SECTION 5.1. COMPANY TO MAINTAIN ITS CORPORATE EXISTENCE; CONDITIONS UNDER
WHICH EXCEPTIONS PERMITTED. The Company agrees that during the term of this
Agreement, it will maintain its corporate existence and its good standing in the
State, will not dissolve or otherwise dispose of all or substantially all of its
assets and will not consolidate with or merge into another corporation unless
the acquirer of its assets or the corporation with which it shall consolidate or
into which it shall merge shall (i) be a corporation organized under the laws of
one of the states of the United States of America, (ii) be qualified to do
business in the State, and (iii) assume in writing all of the obligations of the
Company under this Agreement and the Tax Agreement. Any transfer of all or
substantially all of the Company's generation assets shall not be deemed to
constitute a "disposition of all or substantially all of the Company's assets"
within the meaning of the preceding paragraph. Any such transfer of the
Company's generation assets shall not relieve the Company of any of its
obligations under this Agreement.
The Company hereby agrees that so long as any of the Bonds are insured by a
Bond Insurance Policy issued by the Bond Insurer and the Bond Insurer shall not
have failed to comply with its payment obligations under such Policy, in the
event of a Reorganization, unless otherwise consented to by the Bond Insurer,
the obligations of the Company under, and in respect of, the Bonds, the G&R
Notes, the G&R Indenture and the Agreement shall be assumed
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by, and shall become direct and primary obligations of, a Regulated Utility
Company such that at all times the obligor under this Agreement and the obligor
on the G&R Notes is a Regulated Utility Company. The Company shall deliver to
the Bond Insurer a certificate of the president, any vice president or the
treasurer and an opinion of counsel reasonably acceptable to the Bond Insurer
stating in each case that such Reorganization complies with the provisions of
this paragraph.
The Company need not comply with any of the provisions of this Section 5.1
if, at the time of such merger or consolidation, the Bonds will be defeased as
provided in Article VIII of the Indenture. The Company need not comply with the
provisions of the second paragraph of this Section 5.1 if the Bonds are redeemed
as provided in Section 3.01(B)(3) of the Indenture or if the Bond Insurance
Policy is terminated as described in Section 3.06 of the Indenture in connection
with a purchase of the Bonds by the Company in lieu of their redemption.
SECTION 5.2. ANNUAL STATEMENT. The Company agrees to have an annual audit
made by its regular independent certified public accountants and to furnish the
Trustee (within 30 days after receipt by the Company) with a balance sheet and
statement of income and surplus showing the financial condition of the Company
and its consolidated subsidiaries, if any, at the close of each fiscal year and
the results of operations of the Company and its consolidated subsidiaries, if
any, for each fiscal year, accompanied by a report of said accountants that such
statements have been prepared in accordance with generally accepted accounting
principles. The Company's obligations under this Section 5.2 may be satisfied by
delivering a copy of the Company's Annual Report on Form 10-K to the Trustee
within 10 days after it is filed with the Securities and Exchange Commission.
Delivery of such reports, information and documents to the Trustee is for
informational purposes only and the Trustee's receipt of such shall not
constitute constructive notice of any information contained therein or
determinable from information contained therein, including the Company's
compliance with any of its covenants hereunder (as to which the Trustee is
entitled to rely exclusively on officer's certificates).
SECTION 5.3. MAINTENANCE AND REPAIR; INSURANCE; TAXES; DISPOSITION. For so
long as the Company shall own the Project or portion thereof (i) the Company
shall maintain or cause to be maintained the Project (or portion thereof) in
good repair and keep it properly insured and shall promptly pay or cause to be
paid all costs thereof, and (ii) the Company shall promptly pay or cause to be
paid all installments of taxes, installments of special assessments, and all
governmental, utility and other charges with respect to the Project (or portion
thereof), when due. The Company may, at its own expense and in its own name in
good faith contest or appeal any such taxes, assessments or other charges, or
installments thereof, but shall not permit any such taxes, assessments or other
charges, or installments thereof, to remain unpaid if such nonpayment shall
subject the Project or any part thereof to loss or forfeiture. The Company,
subject to the provisions of Section 3.4 hereof, is not required by this
Agreement to operate, or cause to be operated, any portion of the Project owned
by the Company after the Company shall deem in its discretion that such
continued operation by the Company is not advisable, and in such event the
Company may sell, lease or retire all or any such portion of the Project.
Subject to the provisions of Section 3.4 hereof, the net proceeds from such
sale, lease or other disposition, if any, shall
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belong to, and may be used for any lawful purpose by, the Company. Upon
disposition of the Project in its entirety by the Company in accordance with
this Section 5.3, the Company shall be discharged from its obligations to
operate, maintain, repair and insure the Project as set forth in this Section
5.3. Any such sale, lease or other disposition shall comply with the
requirements of the Tax Agreement. Under any and all circumstances, the Issuer
shall have no obligation whatsoever with respect to the operation, maintenance,
repair or insurance of the Project.
SECTION 5.4. RECORDATION AND OTHER INSTRUMENTS. The Company shall cause
such security agreements, financing statements and all supplements thereto and
other instruments as may be required from time to time to be kept, to be
recorded and filed in such manner and in such places as may be required by law
in order to fully preserve, protect and perfect the security of the Owners of
the Bonds and the rights of the Trustee, and to perfect the security interest
created by the Indenture. The Company agrees to abide by the provisions of
Section 5.11 of the Indenture to the extent applicable to the Company.
SECTION 5.5. NO WARRANTY BY THE ISSUER. The Issuer makes no warranty,
either express or implied, as to the Project or that it will be suitable for the
purposes of the Company or needs of the Company.
SECTION 5.6. AGREEMENT AS TO OWNERSHIP OF THE PROJECT. The Issuer and the
Company agree that title to the Project shall not be in the Issuer, and that the
Issuer shall have no interest in the Project.
SECTION 5.7. COMPANY TO FURNISH NOTICE OF RATE PERIOD ADJUSTMENTS;
LIQUIDITY FACILITY REQUIREMENTS; AUCTION RATE PERIOD PROVISIONS. The Company is
hereby granted the option to designate from time to time changes in Rate Periods
(and to rescind such changes) in the manner and to the extent set forth in
Section 2.03 of the Indenture. In the event the Company elects to exercise any
such option, the Company agrees that it shall cause notices of adjustments of
Rate Periods (or rescissions thereof) to be given to the Issuer, the Trustee and
the Remarketing Agent in accordance with Section 2.03(a), (b), (c), (d) or (e)
of the Indenture, and a copy of each such notice shall also be given at such
time to S&P and Moody's.
The Company hereby agrees that, so long as the Bonds are insured by a Bond
Insurance Policy issued by the Bond Insurer and notwithstanding the provisions
of Section 2.03 of the Indenture, it shall not give notice of its intention to
adjust the Rate Period for the Bonds to a Daily Rate Period, a Weekly Rate
Period or a Flexible Rate Period until the Company shall provide a liquidity
facility reasonably acceptable to the Bond Insurer from a liquidity facility
provider reasonably acceptable to the Bond Insurer in accordance with the Bond
Insurer's liquidity facility requirements to be effective on the related date of
adjustment.
If during any Auction Rate Period (i) consisting of Auction Periods of 35
days or less, the Bonds shall bear interest at the Maximum Interest Rate for a
period in excess of 180 days, or (ii) consisting of one Auction Period of 180
days or more, the Bonds shall bear interest at the Maximum Interest Rate for
such Period, the Company shall notify the Bond Insurer in writing of such event
and agrees to cooperate with the Bond Insurer to take all steps reasonably
necessary to adjust the Rate Period on the Bonds as soon as reasonably
practicable in accordance with the
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provisions of the Indenture to the Rate Period which the Remarketing Agent
advises the Company and the Bond Insurer will be the lowest interest rate
(taking into account all relevant costs) which would enable the Remarketing
Agent to sell all the Bonds on the date of such adjustment at a price equal to
100% of the principal amount thereof (the "Lowest Interest Rate Period"). If at
such time the Company shall be in default under the Agreement but the Bond
Insurer shall not have failed to comply with its payment obligations under the
Bond Insurance Policy, the Bond Insurer may, in its discretion, direct the
Company to provide notice of the adjustment of the Rate Period on the Bonds to
the Lowest Interest Rate Period in accordance with the provisions of Section
2.03 of the Indenture.
SECTION 5.8. INFORMATION REPORTING, ETC. The Issuer covenants and agrees
that, upon the direction of the Company or Bond Counsel, it will mail or cause
to be mailed to the Secretary of the Treasury (or his designee as prescribed by
regulation, currently the Internal Revenue Service Center, Ogden, Utah) a
statement setting forth the information required by Section 149(e) of the Code,
which statement shall be in the form of the Information Return for Tax-Exempt
Private Activity Bond Issues (Form 8038) of the Internal Revenue Service (or any
successor form) and which shall be completed by the Company and Bond Counsel
based in part upon information supplied by the Company and Bond Counsel.
SECTION 5.9. LIMITED LIABILITY OF ISSUER. Any obligation or liability of
the Issuer created by or arising out of this Agreement or otherwise incurred in
connection with the issuance of the Bonds (including without limitation any
liability created by or arising out of the representations, warranties or
covenants set forth herein or otherwise) shall not impose a debt or pecuniary
liability upon the Issuer or the State or any political subdivision thereof, or
a charge upon the general credit or taxing powers of any of the foregoing, but
shall be payable solely out of the Revenues or other amounts payable by the
Company to the Issuer hereunder or otherwise (including without limitation any
amounts derived from indemnifications given by the Company).
Neither the issuance of the Bonds nor the delivery of this Agreement shall,
directly or indirectly or contingently, obligate the Issuer or the State or any
political subdivision thereof to levy any form of taxation therefor or to make
any appropriation for their payment. Nothing in the Bonds or in the Indenture or
this Agreement or the proceedings of the Issuer authorizing the Bonds or in the
Act or in any other related document shall be construed to authorize the Issuer
to create a debt of the Issuer or the State or any political subdivision thereof
within the meaning of any constitutional or statutory provision of the State.
The principal of, and premium, if any, and interest on, the Bonds shall be
payable solely from the funds pledged for their payment in accordance with the
Indenture and available therefor under this Agreement. Neither the State nor any
political subdivision thereof shall in any event be liable for the payment of
the principal of, premium, if any, or interest on, the Bonds or for the
performance of any pledge, obligation or agreement of any kind whatsoever which
may be undertaken by the Issuer. No breach of any such pledge, obligation or
agreement may impose any pecuniary liability upon the Issuer or the State or any
political subdivision thereof, or any charge upon the general credit or against
the taxing power of the Issuer or the State or any political subdivision
thereof.
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SECTION 5.10. INSPECTION OF PROJECT. The Company agrees that the Issuer and
the Trustee and their duly authorized representatives shall have the right at
all reasonable times to enter upon and examine and inspect the Project property
(other than the Water Project) and shall also be permitted, at all reasonable
times, to examine the books and records of the Company insofar as they relate to
the Project (other than the Water Project).
SECTION 5.11. INDENTURE COVENANTS. The Company covenants to observe and
perform all of the obligations imposed on it under the Indenture.
ARTICLE VI
EVENTS OF DEFAULT AND REMEDIES
SECTION 6.1. EVENTS OF DEFAULT DEFINED. The following shall be "events of
default" under this Agreement and the terms "event of default" or "default"
shall mean, whenever they are used in this Agreement, any one or more of the
following events:
(a) Failure by the Company to pay when due any amounts required to be
paid under Section 4.2(a) hereof, which failure results in an event of
default under subparagraph (a) or (b) of Section 9.01 of the Indenture; or
(b) Failure by the Company to pay or cause to be paid any payment
required to be paid under Section 4.2(b) hereof, which failure results in
an event of default under subparagraph (c) of Section 9.01 of the
Indenture; or
(c) Failure by the Company to observe and perform any covenant,
condition or agreement on its part to be observed or performed in this
Agreement, other than as referred to in (a) and (b) above, for a period of
90 days after written notice, specifying such failure and requesting that
it be remedied and stating that such notice is a "Notice of Default"
hereunder, given to the Company by the Trustee or to the Company and the
Trustee by the Issuer, unless the Issuer and the Trustee shall agree in
writing to an extension of such time prior to its expiration; provided,
however, if the failure stated in the notice cannot be corrected within the
applicable period, the Issuer and the Trustee will not unreasonably
withhold their consent to an extension of such time if corrective action is
instituted within the applicable period and diligently pursued until the
failure is corrected and such corrective action or diligent pursuit is
evidenced to the Trustee by a certificate of an Authorized Company
Representative; or
(d) A proceeding or case shall be commenced, without the application
or consent of the Company, in any court of competent jurisdiction seeking
(i) liquidation, reorganization, dissolution, winding-up or composition or
adjustment of debts, (ii) the appointment of a trustee, receiver,
custodian, liquidator or the like of the Company or of all or any
substantial part of its assets, or (iii) similar relief under any law
relating to bankruptcy, insolvency, reorganization, winding-up or
composition or adjustment of debts, and such proceeding or cause shall
continue undismissed, or an order, judgment, or decree approving or
ordering any of the foregoing shall be entered and shall continue in
-16-
effect for a period of 90 days; or an order for relief against the Company
shall be entered against the Company in an involuntary case under the
Bankruptcy Code (as now or hereafter in effect) or other applicable law; or
(e) The Company shall admit in writing its inability to pay its debts
generally as they become due or shall file a petition in voluntary
bankruptcy or shall make any general assignment for the benefit of its
creditors, or shall consent to the appointment of a receiver or trustee of
all or substantially all of its property, or shall commence a voluntary
case under the Bankruptcy Code (as now or hereafter in effect), or shall
file in any court of competent jurisdiction a petition seeking to take
advantage of any other law relating to bankruptcy, insolvency,
reorganization, winding-up or composition or adjustment of debts, or shall
fail to controvert in a timely or appropriate manner, or acquiesce in
writing to, any petition filed against it in an involuntary case under such
Bankruptcy Code or other applicable law; or
(f) Dissolution or liquidation of the Company; provided that the term
"dissolution or liquidation of the Company" shall not be construed to
include the cessation of the corporate existence of the Company resulting
either from a merger or consolidation of the Company into or with another
corporation or a dissolution or liquidation of the Company following a
transfer of all or substantially all of its assets as an entirety, under
the conditions permitting such actions contained in Section 5.1 hereof; or
(g) The occurrence of an "event of default" under the Indenture.
The foregoing provisions of Section 6.1(c) are subject to the following
limitations: If by reason of Force Majeure the Company is unable in whole or in
part to carry out its agreements on its part herein contained, other than the
obligations on the part of the Company contained in Article IV and Sections 5.3
and 6.4 hereof, the Company shall not be deemed in default during the
continuance of such inability. The Company agrees, however, to remedy with all
reasonable dispatch the cause or causes preventing the Company from carrying out
its agreements; provided that the settlement of strikes, lockouts and other
industrial disturbances shall be entirely within the discretion of the Company
and the Company shall not be required to make settlement of strikes, lockouts
and other industrial disturbances by acceding to the demands of the opposing
party or parties when such course is in the sole judgment of the Company
unfavorable to the Company.
SECTION 6.2. REMEDIES ON DEFAULT. Whenever any event of default referred to
in Section 6.1 hereof shall have happened and be continuing, the Trustee, as
assignee of the Issuer:
(a) shall, by notice in writing to the Company, declare the unpaid
indebtedness under Section 4.2(a) hereof to be due and payable immediately,
if concurrently with or prior to such notice the unpaid principal amount of
the Bonds shall have been declared to be due and payable, and upon any such
declaration the same (being an amount sufficient, together with other
moneys available therefor in the Bond Fund, to
-17-
pay the unpaid principal of, premium, if any, and interest accrued on, the
Bonds) shall become and shall be immediately due and payable as liquidated
damages; and
(b) may take whatever action at law or in equity as may appear
necessary or desirable to collect the payments and other amounts then due
and thereafter to become due hereunder or to enforce performance and
observance of any obligation, agreement or covenant of the Company under
this Agreement.
Any amounts collected pursuant to action taken under this Section 6.2 shall
be paid into the Bond Fund (unless otherwise provided in this Agreement) and
applied in accordance with the provisions of the Indenture. No action taken
pursuant to this Section 6.2 shall relieve the Company from the Company's
obligations pursuant to Section 4.2 hereof.
No recourse shall be had for any claim based on this Agreement against any
officer, director or stockholder, past, present or future, of the Company as
such, either directly or through the Company, under any constitutional
provision, statute or rule of law, or by the enforcement of any assessment or by
any legal or equitable proceeding or otherwise.
Nothing herein contained shall be construed to prevent the Issuer from
enforcing directly any of its rights under Sections 4.2(e), 4.2(g), 5.3 and 6.4
hereof.
The Company shall promptly notify the Issuer of any action taken by the
Company under the grant of authority from the Issuer under the last paragraph of
Section 9.01 of the Indenture.
SECTION 6.3. NO REMEDY EXCLUSIVE. No remedy herein conferred upon or
reserved to the Issuer is intended to be exclusive of any other available remedy
or remedies, but each and every such remedy shall be cumulative and shall be in
addition to every other remedy given under this Agreement or now or hereafter
existing at law or in equity or by statute. No delay or omission to exercise any
right or power accruing upon any default shall impair any such right or power or
shall be construed to be a waiver thereof, but any such right and power may be
exercised from time to time and as often as may be deemed expedient. In order to
entitle the Issuer or the Trustee to exercise any remedy reserved to it in this
Article, it shall not be necessary to give any notice, other than such notice as
may be herein expressly required. Subject to the provisions of the Indenture and
hereof, such rights and remedies as are given the Issuer hereunder shall also
extend to the Trustee. The Owners of the Bonds, subject to the provisions of the
Indenture, shall be entitled to the benefit of all covenants and agreements
herein contained.
SECTION 6.4. AGREEMENT TO PAY FEES AND EXPENSES OF COUNSEL. In the event
the Company should default under any of the provisions of this Agreement and the
Issuer or the Trustee should employ Counsel or incur other expenses for the
collection of the indebtedness hereunder or the enforcement of performance or
observance of any obligation or agreement on the part of the Company herein
contained, the Company agrees that it will on written demand therefor pay to the
Trustee or the Issuer (or to the Counsel for either of such parties if directed
by such party), the reasonable fees and expenses of such Counsel and such other
expenses so incurred by or on behalf of the Issuer or the Trustee.
-18-
SECTION 6.5. NO ADDITIONAL WAIVER IMPLIED BY ONE WAIVER; CONSENTS TO
WAIVERS. In the event any agreement contained in this Agreement should be
breached by either party and thereafter waived by the other party, such waiver
shall be limited to the particular breach so waived and shall not be deemed to
waive any other breach hereunder. No waiver shall be effective unless in writing
and signed by the party making the waiver. The Issuer shall have no power to
waive any default hereunder by the Company without the consent of the Trustee to
such waiver. The Trustee shall have the power to waive any default by the
Company hereunder, except a default under Section 3.4, 4.2(e), 4.2(g), 5.3 or
6.4 hereof, in so far as it pertains to the Issuer, without the prior written
concurrence of the Issuer. Notwithstanding the foregoing, if, after the
acceleration of the maturity of the outstanding Bonds by the Trustee pursuant to
Section 9.02 of the Indenture, (i) all arrears of principal of and interest on
the outstanding Bonds and interest on overdue principal and (to the extent
permitted by law) on overdue installments of interest at the rate of interest
borne by the Bonds on the date on which such principal or interest became due
and payable and the premium, if any, on all Bonds then Outstanding which have
become due and payable otherwise than by acceleration, and all other sums
payable under the Indenture, except the principal of and the interest on such
Bonds which by such acceleration shall have become due and payable, shall have
been paid, (ii) all other things shall have been performed in respect of which
there was a default, (iii) there shall have been paid the reasonable fees and
expenses of the Trustee and of the Owners of such Bonds, including reasonable
attorneys' fees paid or incurred and (iv) such event of default under the
Indenture shall be waived in accordance with Section 9.09 of the Indenture with
the consequence that such acceleration under Section 9.02 of the Indenture is
rescinded, then the Company's default hereunder shall be deemed to have been
waived and its consequences rescinded and no further action or consent by the
Trustee or the Issuer shall be required; provided that there has been furnished
an opinion of Bond Counsel to the effect that such waiver will not adversely
affect the exemption from federal income taxes of interest on the Bonds.
ARTICLE VII
OPTIONS AND OBLIGATIONS OF COMPANY;
PREPAYMENTS; REDEMPTION OF BONDS
SECTION 7.1. OPTION TO PREPAY. The Company shall have, and is hereby
granted, the option to prepay the payments due hereunder in whole or in part at
any time or from time to time (a) to provide for the redemption of Bonds
pursuant to the provisions of Section 3.01(A) of the Indenture or (b) to
provide for the defeasance of the Bonds pursuant to Article VIII of the
Indenture. In the event the Company elects to provide for the redemption of
Bonds as permitted by this Section, the Company shall notify and instruct the
Trustee in accordance with Section 7.3 hereof to redeem all or any portion of
the Bonds in advance of maturity. If the Company so elects, any redemption of
Bonds pursuant to Section 3.01(A) of the Indenture may be made conditional.
SECTION 7.2. OBLIGATION TO PREPAY. The Company covenants and agrees that if
all or any part of the Bonds are unconditionally called for redemption in
accordance with the Indenture or become subject to mandatory redemption (except
as otherwise provided in Section 3.02 of the
-19-
Indenture), it will prepay the indebtedness hereunder in whole or in part in an
amount sufficient to redeem such Bonds on the date fixed for the redemption of
such Bonds.
SECTION 7.3. NOTICE OF PREPAYMENT. Upon the exercise of the option granted
to the Company in Section 7.1 hereof, or upon the Company having knowledge of
the occurrence of any event requiring mandatory redemption of the Bonds in
accordance with Section 3.01(B) of the Indenture, the Company shall give written
notice to the Issuer, the Remarketing Agent, the Auction Agent and the Trustee.
The notice shall provide for the date of the application of the prepayment made
by the Company hereunder to the retirement of the Bonds in whole or in part
pursuant to call for redemption and shall be given by the Company not less than
five Business Days prior to the date notice of such redemption must be given by
the Trustee to the Bondholders as provided in Section 3.02 of the Indenture or
such later date as is acceptable to the Trustee and the Issuer.
ARTICLE VIII
MISCELLANEOUS
SECTION 8.1. NOTICES. (a) Except as otherwise provided herein, all notices,
certificates or other communications hereunder shall be sufficiently given if in
writing and shall be deemed given when mailed by first class mail, postage
prepaid, or by qualified overnight courier service, courier charges prepaid, or
by facsimile (receipt of which is orally confirmed) addressed as follows: if to
the Issuer, at 1001 East Ninth Street, Building A, Room 225, Reno, Nevada 89512,
or to telecopy number (775) 328-2037, Attention: Finance Director; if to the
Company, at 6100 Neil Road, Reno, Nevada 89520, or to telecopy number (702)
227-2250, Attention: Treasurer; if to the Trustee, at 385 Rifle Camp Road, West
Paterson, New Jersey 07424, or to telecopy number (973) 357-7840, Attention:
Corporate Trust Services; if to the Remarketing Agent, at the address set forth
in the Remarketing Agreement, if any; and if to the Auction Agent, at the
address set forth in the Auction Agreement, if any. In case by reason of the
suspension of regular mail service, it shall be impracticable to give notice by
first class mail of any event to the Issuer, to the Company, to the Remarketing
Agent, to the Auction Agent when such notice is required to be given pursuant to
any provisions of this Agreement, then any manner of giving such notice as shall
be satisfactory to the Trustee shall be deemed to be sufficient giving of such
notice. The Issuer, the Company, the Trustee, the Remarketing Agent and the
Auction Agent may, by notice pursuant to this Section 8.1, designate any
different addresses to which subsequent notices, certificates or other
communications shall be sent.
(b) The Trustee agrees to accept and act upon instructions or
directions pursuant to this Agreement sent by unsecured e-mail, facsimile
transmission or other similar unsecured electronic methods, provided,
however, that (a) the Company and/or Issuer, subsequent to such
transmission of written instructions, shall, upon request by the Trustee,
provide the originally executed instructions or directions to the Trustee,
(b) upon request by the Trustee, such originally executed instructions or
directions shall be signed by a person as may be designated and authorized
to sign for the Company and/or Issuer or in the name of the Company and/or
Issuer, by an authorized representative of the Company and/or Issuer, and
(c) upon the request by the Trustee, the Company and/or Issuer shall
provide to the Trustee an incumbency certificate listing
-20-
such designated persons, which incumbency certificate shall be amended
whenever a person is to be added or deleted from the listing. If the
Company and/or Issuer elects to give the Trustee e-mail or facsimile
instructions (or instructions by a similar electronic method) and the
Trustee elects to act upon such instructions, the Trustee's reasonable
interpretation and understanding of such instructions shall be deemed
controlling. The Trustee shall not be liable for any losses, costs or
expenses arising directly or indirectly from the Trustee's reasonable
reliance upon and compliance with such instructions notwithstanding that
such instructions conflict or are inconsistent with a subsequent written
instruction.
SECTION 8.2. ASSIGNMENTS. This Agreement may not be assigned by either
party without consent of the other and the Trustee, except that the Issuer shall
assign to the Trustee its rights under this Agreement (except under Sections
4.2(e), 4.2(g), 5.3, and 6.4 hereof) as provided by Section 4.4 hereof, and the
Company may assign its rights under this Agreement to any transferee or any
surviving or resulting corporation as provided by Section 5.1 hereof.
SECTION 8.3. SEVERABILITY. If any provision of this Agreement shall be held
or deemed to be or shall, in fact, be illegal, inoperative or unenforceable, the
same shall not affect any other provision or provisions herein contained or
render the same invalid, inoperative, or unenforceable to any extent whatever.
SECTION 8.4. EXECUTION OF COUNTERPARTS. This Agreement may be
simultaneously executed in several counterparts, each of which shall be an
original and all of which shall constitute but one and the same instrument.
SECTION 8.5. AMOUNTS REMAINING IN BOND FUND. It is agreed by the parties
hereto that after payment in full of (i) the Bonds (or provision for payment
thereof having been made in accordance with the provisions of the Indenture),
(ii) the fees, charges and expenses of the Trustee in accordance with the
Indenture, (iii) the Administrative Expenses, (iv) the fees and expenses of the
Remarketing Agent, the Auction Agent and the Issuer and (v) all other amounts
required to be paid under this Agreement and the Indenture, any amounts
remaining in the Bond Fund shall belong to and be paid to the Company by the
Trustee.
SECTION 8.6. AMENDMENTS, CHANGES AND MODIFICATIONS. This Agreement may be
amended, changed, modified, altered or terminated only by written instrument
executed by the Issuer and the Company, and only if the written consent of the
Trustee thereto is obtained, and only in accordance with the provisions of
Article XII of the Indenture.
SECTION 8.7. GOVERNING LAW. This Agreement shall be governed exclusively by
and construed in accordance with the applicable laws of the State.
SECTION 8.8. AUTHORIZED ISSUER AND COMPANY REPRESENTATIVES. Whenever under
the provisions of this Agreement the approval of the Issuer or the Company is
required to take some action at the request of the other, such approval of such
request shall be given for the Issuer by the Authorized Issuer Representative
and for the Company by the Authorized Company Representative, and the other
party hereto and the Trustee shall be authorized to act on any such
-21-
approval or request and neither party hereto shall have any complaint against
the other or against the Trustee as a result of any such action taken.
SECTION 8.9. TERM OF THE AGREEMENT. This Agreement shall be in full force
and effect from its date to and including such date as all of the Bonds issued
under the Indenture shall have been fully paid or retired (or provision for such
payment shall have been made as provided in the Indenture), provided that all
representations and certifications by the Company as to all matters affecting
the tax-exempt status of the Bonds and the covenants of the Company in Sections
4.2(c), 4.2(d), 4.2(e), 4.2(f) and 4.2(g) hereof shall survive the termination
of this Agreement.
SECTION 8.10. CANCELLATION AT EXPIRATION OF TERM. At the acceleration,
termination or expiration of the term of this Agreement and following full
payment of the Bonds or provision for payment thereof and of all other fees and
charges having been made in accordance with the provisions of this Agreement and
the Indenture, the Issuer shall deliver to the Company any documents and take or
cause the Trustee to take such actions as may be necessary to effectuate the
cancellation and evidence the termination of this Agreement.
SECTION 8.11. BOND INSURANCE. The payment of the principal of and interest
on the Bonds when due is to be insured under, and to the extent provided in, the
Bond Insurance Policy, including the endorsements thereto, to be issued by the
Bond Insurer, and the Issuer and the Company agree to be bound by the provisions
contained in Appendix C to the Indenture and the Company agrees to be bound by
the provisions contained in the Insurance Agreement. In the event of any
conflict between the provisions of Appendix C to the Indenture and the
provisions of this Agreement, the provisions of Appendix C shall govern and
control.
All references in this Agreement to the Bond Insurer shall only apply so
long as a Bond Insurance Policy issued by the Bond Insurer is in effect for any
of the Bonds (and the Bond Insurer has not failed to comply with its payment
obligations under the Bond Insurance Policy).
-22-
IN WITNESS WHEREOF, the Issuer and the Company have caused this Agreement
to be executed in their respective corporate names and their respective
corporate seals to be hereunto affixed and attested by their duly authorized
officers, all as of the date First above written.
WASHOE COUNTY, NEVADA
By
Chairman
Board of County Commissioners
(SEAL)
Attest:
County Clerk
SIERRA PACIFIC POWER COMPANY
By
Treasurer
(SEAL)
Attest:
Secretary
-22-
IN WITNESS WHEREOF, the Issuer and the Company have caused this Agreement
to be executed in their respective corporate names and their respective
corporate seals to be hereunto affixed and attested by their duly authorized
officers, all as of the date first above written.
WASHOE COUNTY, NEVADA
By
Chairman
Board of County Commissioners
(SEAL)
Attest:
County Clerk
SIERRA PACIFIC POWER COMPANY
By
Vice President, Finance and Risk, and
Treasurer
(SEAL)
Attest:
Secretary
EXHIBIT 12 (A)
SIERRA PACIFIC RESOURCES
RATIOS OF EARNINGS TO FIXED CHARGES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Amounts in 000’s
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
EARNINGS AS DEFINED:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) From Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After Interest Charges
|
|
$
|
279,792
|
|
|
$
|
86,137
|
|
|
$
|
30,842
|
|
|
$
|
(117,286
|
)
|
|
$
|
(297,733
|
)
|
|
Income Taxes
|
|
|
145,605
|
|
|
|
43,118
|
|
|
|
18,050
|
|
|
|
(51,275
|
)
|
|
|
(162,134
|
)
|
|
|
|
|
|
Income (Loss) From Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
before Income Taxes
|
|
|
425,397
|
|
|
|
129,255
|
|
|
|
48,892
|
|
|
|
(168,561
|
)
|
|
|
(459,867
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Charges
|
|
|
336,024
|
|
|
|
319,654
|
|
|
|
324,969
|
|
|
|
384,565
|
|
|
|
295,877
|
|
|
Capitalized Interest
|
|
|
(17,119
|
)
|
|
|
(24,691
|
)
|
|
|
(8,587
|
)
|
|
|
(5,976
|
)
|
|
|
(5,270
|
)
|
|
Preferred Stock Dividend Requirement
|
|
|
(3,602
|
)
|
|
|
(6,000
|
)
|
|
|
(6,000
|
)
|
|
|
(6,000
|
)
|
|
|
(6,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
740,700
|
|
|
$
|
418,218
|
|
|
$
|
359,274
|
|
|
$
|
204,028
|
|
|
$
|
(175,260
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIXED CHARGES AS DEFINED:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expensed and Capitalized (1)
|
|
$
|
332,422
|
|
|
$
|
313,654
|
|
|
$
|
318,969
|
|
|
$
|
378,565
|
|
|
$
|
289,877
|
|
|
Preferred Stock Dividend Requirement
|
|
|
3,602
|
|
|
|
6,000
|
|
|
|
6,000
|
|
|
|
6,000
|
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
336,024
|
|
|
|
319,654
|
|
|
$
|
324,969
|
|
|
$
|
384,565
|
|
|
$
|
295,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RATIO OF EARNINGS TO FIXED CHARGES
|
|
|
2.20
|
|
|
|
1.31
|
|
|
|
1.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFICIENCY
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
180,537
|
|
|
$
|
471,137
|
|
|
|
|
|
|
(1)
|
|
Includes amortization of premiums, discounts, and capitalized debt expense and interest component of
rent expense.
|
For the purpose of calculating the ratios of earnings to fixed charges, “Fixed charges”
represent the aggregate of interest charges on short-term and long-term debt, allowance for
borrowed funds used during construction (AFUDC) and capitalized interest, the portion of rental
expense deemed to be attributable to interest, and the pre-tax preferred stock dividend requirement
of SPPC. “Earnings” represent pre-tax income (or Loss) from continuing operations before pre-tax
preferred stock dividend requirement of SPPC, fixed charges and capitalized interest.
EXHIBIT 12 (B)
NEVADA POWER COMPANY
RATIOS OF EARNINGS TO FIXED CHARGES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Amounts in 000’s
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
EARNINGS AS DEFINED:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) From Continuing Operations
After Interest Charges
|
|
$
|
224,540
|
|
|
$
|
132,734
|
|
|
$
|
104,312
|
|
|
$
|
19,277
|
|
|
$
|
(235,070
|
)
|
|
Income Taxes
|
|
|
117,510
|
|
|
|
63,995
|
|
|
|
56,572
|
|
|
|
(614
|
)
|
|
|
(131,784
|
)
|
|
|
|
|
|
Income (Loss) From Continuing Operations
before Income Taxes
|
|
|
342,050
|
|
|
|
196,729
|
|
|
|
160,884
|
|
|
|
18,663
|
|
|
|
(366,854
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Charges
|
|
|
190,333
|
|
|
|
159,776
|
|
|
|
145,055
|
|
|
|
195,342
|
|
|
|
137,968
|
|
|
Capitalized Interest
|
|
|
(11,614
|
)
|
|
|
(23,187
|
)
|
|
|
(5,738
|
)
|
|
|
(2,700
|
)
|
|
|
(3,412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
520,769
|
|
|
$
|
333,318
|
|
|
$
|
300,201
|
|
|
$
|
211,305
|
|
|
$
|
(232,298
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIXED CHARGES AS DEFINED:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expensed and Capitalized (1)
|
|
$
|
190,333
|
|
|
$
|
159,776
|
|
|
$
|
145,055
|
|
|
$
|
195,342
|
|
|
$
|
137,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
190,333
|
|
|
$
|
159,776
|
|
|
$
|
145,055
|
|
|
$
|
195,342
|
|
|
$
|
137,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RATIO OF EARNINGS TO FIXED CHARGES
|
|
|
2.74
|
|
|
|
2.09
|
|
|
|
2.07
|
|
|
|
1.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFICIENCY
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
370,266
|
|
For the purpose of calculating the ratios of earnings to fixed charges, “Fixed charges”
represent the aggregate of interest charges on short-term and long-term debt, allowance for
borrowed funds used during construction (AFUDC) and capitalized interest, and the portion of rental
expense deemed to be attributable to interest. “Earnings” represents pre-tax income (or loss) from
continuing operations before fixed charges and capitalized interest.
EXHIBIT 12 (C)
SIERRA PACIFIC POWER COMPANY
RATIOS OF EARNINGS TO FIXED CHARGES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
Amounts in 000’s
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
EARNINGS AS DEFINED:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) From Continuing Operations
After Interest Charges
|
|
$
|
57,709
|
|
|
$
|
52,074
|
|
|
$
|
18,577
|
|
|
$
|
(23,275
|
)
|
|
$
|
(13,968
|
)
|
|
Income Taxes
|
|
$
|
27,829
|
|
|
|
28,379
|
|
|
|
325
|
|
|
|
(12,237
|
)
|
|
|
(4,491
|
)
|
|
|
|
|
|
Income (Loss) From Continuing Operations
before Income Taxes
|
|
|
85,538
|
|
|
|
80,453
|
|
|
|
18,902
|
|
|
|
(35,512
|
)
|
|
|
(18,459
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Charges
|
|
|
79,093
|
|
|
|
72,652
|
|
|
|
67,685
|
|
|
|
101,514
|
|
|
|
79,303
|
|
|
Capitalized Interest
|
|
$
|
(5,505
|
)
|
|
|
(1,504
|
)
|
|
|
(2,849
|
)
|
|
|
(3,276
|
)
|
|
|
(1,858
|
)
|
|
|
|
|
|
Total
|
|
$
|
159,126
|
|
|
$
|
151,601
|
|
|
$
|
83,738
|
|
|
$
|
62,726
|
|
|
$
|
58,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIXED CHARGES AS DEFINED:
|
|
$
|
79,093
|
|
|
$
|
72,652
|
|
|
$
|
67,685
|
|
|
$
|
101,514
|
|
|
$
|
79,303
|
|
|
Interest Expensed and Capitalized (1)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
Total
|
|
|
79,093
|
|
|
|
72,652
|
|
|
$
|
67,685
|
|
|
$
|
101,514
|
|
|
$
|
79,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RATIO OF EARNINGS TO FIXED CHARGES
|
|
|
2.01
|
|
|
|
2.09
|
|
|
|
1.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFICIENCY
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
38,788
|
|
|
$
|
20,317
|
|
For the purpose of calculating the ratios of earnings to fixed charges, “Fixed charges”
represent the aggregate of interest charges on short-term and long-term debt, allowance for
borrowed funds used during construction (AFUDC) and capitalized interest, and the portion of rental
expense deemed to be attributable to interest. “Earnings” represents pre-tax income (or loss) from
continuing operations before pre-tax preferred stock dividend requirement, fixed charges and
capitalized interest.
Exhibit 23(A)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement
No. 333-77523 on Form S-3, Registration Statement No. 333-92651 on
Form S-8, Registration Statement No. 333-130186 on Form S-4, Registration
Statement No. 333-72160 on Form S-3/A, and Registration Statement
No. 333-135752 on Form S-3ASR, of our reports dated March 1, 2007,
relating to the consolidated financial statements and financial statement
schedules of Sierra Pacific Resources (which report expresses an unqualified
opinion and includes and explanatory paragraph related to the adoption of
Statement of Financial Accounting Standards No. 123(R) and the adoption of
Statement of Financial Accounting Standards No. 158) and management's
report on the effectiveness of internal control over financial reporting,
appearing in this Annual Report on Form 10-K of Sierra Pacific Resources for the
year ended December 31, 2006.
Deloitte & Touche LLP
Reno, Nevada
March 1, 2007
Exhibit 23(B)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No.
333-130189 on Form S-3, of our report dated March 1, 2007, relating to the
consolidated financial statements and financial statement schedule of Nevada
Power Company (which report expresses an unqualified opinion and includes an
explanatory paragraph related to the adoption of Statement of Financial
Accounting Standards No. 158) appearing in this Annual Report on Form 10-K of
Nevada Power Company for the year ended December 31, 2006.
Deloitte & Touche LLP
Reno, Nevada
March 1, 2007
Exhibit 23(C)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No.
333-130191 on Form S-3, of our report dated March 1, 2007, relating to the
consolidated financial statements and financial statement schedule of Sierra
Pacific Power Company (which report expresses an unqualified opinion and
includes an explanatory paragraph related to the adoption of Statement of
Financial Accounting Standards No. 158) appearing in this Annual Report on Form
10-K of Sierra Pacific Power Company for the year ended December 31, 2006.
Deloitte & Touche LLP
Reno, Nevada
March 1, 2007
Exhibit 31.1
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY
SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002
SIERRA PACIFIC RESOURCES
(“Registrant”)
I, Walter M. Higgins III, certify that:
|
|
1.
|
|
I have reviewed this annual report on Form 10-K of Sierra Pacific Resources;
|
|
|
|
|
2.
|
|
Based on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not misleading with respect to the
period covered by this report;
|
|
|
|
|
3.
|
|
Based on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
|
|
|
|
|
4.
|
|
The registrant’s other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) for the registrant and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)), and we have:
|
|
|
(a)
|
|
Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including their consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
|
|
|
|
|
(b)
|
|
Designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
|
|
|
|
|
(c)
|
|
Evaluated the effectiveness of the registrant’s disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this
report based on such evaluation; and
|
|
|
|
|
(d)
|
|
Disclosed in this report any change in the registrant’s internal control
over financial reporting that occurred during the registrant’s most recent fiscal
quarter that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
|
|
|
5.
|
|
The registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the registrant’s
auditors and the audit committee of registrant’s board of directors:
|
|
|
(a)
|
|
All significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
|
|
|
|
|
(b)
|
|
Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control over
financial reporting.
|
February 28, 2007
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Walter M. Higgins, III
|
|
|
|
Walter M. Higgins III
|
|
|
|
Chief Executive Officer
Sierra Pacific Resources
|
|
|
|
Exhibit 31.2
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY
SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002
NEVADA POWER COMPANY
(“Registrant”)
I, Walter M. Higgins III, certify that:
|
|
1.
|
|
I have reviewed this annual report on Form 10-K of Nevada Power Company;
|
|
|
|
|
2.
|
|
Based on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not misleading with respect to the
period covered by this report;
|
|
|
|
|
3.
|
|
Based on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
|
|
|
|
|
4.
|
|
The registrant’s other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) for the registrant, and we have:
|
|
|
(a)
|
|
Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including their consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
|
|
|
|
|
(b)
|
|
[Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986];
|
|
|
|
|
(c)
|
|
Evaluated the effectiveness of the registrant’s disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this
report based on such evaluation; and
|
|
|
|
|
(d)
|
|
Disclosed in this report any change in the registrant’s internal control
over financial reporting that occurred during the registrant’s most recent fiscal
quarter that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
|
|
|
5.
|
|
The registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the registrant’s
auditors and the audit committee of registrant’s board of directors:
|
|
|
(a)
|
|
All significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
|
|
|
|
|
(b)
|
|
Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control over
financial reporting.
|
February 28, 2007
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Walter M. Higgins, III
|
|
|
|
Walter M. Higgins III
|
|
|
|
Chief Executive Officer
Nevada Power Company
|
|
|
|
Exhibit 31.3
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY
SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002
SIERRA PACIFIC POWER COMPANY
(“Registrant”)
I, Walter M. Higgins III, certify that:
|
|
1.
|
|
I have reviewed this annual report on Form 10-K of Sierra Pacific Power Company;
|
|
|
|
|
2.
|
|
Based on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not misleading with respect to the
period covered by this report;
|
|
|
|
|
3.
|
|
Based on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
|
|
|
|
|
4.
|
|
The registrant’s other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) for the registrant, and we have:
|
|
|
(a)
|
|
Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including their consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
|
|
|
|
|
(b)
|
|
[Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986];
|
|
|
|
|
(c)
|
|
Evaluated the effectiveness of the registrant’s disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this
report based on such evaluation; and
|
|
|
|
|
(d)
|
|
Disclosed in this report any change in the registrant’s internal control
over financial reporting that occurred during the registrant’s most recent fiscal
quarter that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
|
|
|
5.
|
|
The registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the registrant’s
auditors and the audit committee of registrant’s board of directors:
|
|
|
(a)
|
|
All significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
|
|
|
|
|
(b)
|
|
Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control over
financial reporting.
|
February 28, 2007
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Walter M. Higgins, III
|
|
|
|
Walter M. Higgins III
|
|
|
|
Chief Executive Officer
Sierra Pacific Power Company
|
|
|
|
Exhibit 31.4
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY
SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002
SIERRA PACIFIC RESOURCES
(“Registrant”)
I, William D. Rogers, certify that:
|
|
1.
|
|
I have reviewed this annual report on Form 10-K of Sierra Pacific Resources;
|
|
|
|
|
2.
|
|
Based on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not misleading with respect to the
period covered by this report;
|
|
|
|
|
3.
|
|
Based on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
|
|
|
|
|
4.
|
|
The registrant’s other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) for the registrant and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)), and we have:
|
|
|
(a)
|
|
Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including their consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
|
|
|
|
|
(b)
|
|
Designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
|
|
|
|
|
(c)
|
|
Evaluated the effectiveness of the registrant’s disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
|
|
|
|
|
(d)
|
|
Disclosed in this report any change in the registrant’s internal control
over financial reporting that occurred during the registrant’s most recent fiscal
quarter that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
|
|
|
5.
|
|
The registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the registrant’s
auditors and the audit committee of registrant’s board of directors:
|
|
|
(a)
|
|
All significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
|
|
|
|
|
(b)
|
|
Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control over
financial reporting.
|
February 28, 2007
|
|
|
|
|
|
|
|
|
|
|
|
/s/ William D. Rogers
|
|
|
|
William D. Rogers
|
|
|
|
Chief Financial Officer
Sierra Pacific Resources
|
|
|
|
Exhibit 31.5
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY
SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002
NEVADA POWER COMPANY
(“Registrant”)
I, William D. Rogers, certify that:
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1.
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I have reviewed this annual report on Form 10-K of Nevada Power Company;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not misleading with respect to the
period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) for the registrant, and we have:
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(a)
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Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including their consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
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(b)
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[Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986];
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(c)
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Evaluated the effectiveness of the registrant’s disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant’s internal control
over financial reporting that occurred during the registrant’s most recent fiscal
quarter that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the registrant’s
auditors and the audit committee of registrant’s board of directors:
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(a)
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All significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control over
financial reporting.
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February 28, 2007
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/s/ William D. Rogers
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William D. Rogers
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Chief Financial Officer
Nevada Power Company
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Exhibit 31.6
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY
SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002
SIERRA PACIFIC POWER COMPANY
(“Registrant”)
I, William D. Rogers, certify that:
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1.
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I have reviewed this annual report on Form 10-K of Sierra Pacific Power Company;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not misleading with respect to the
period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) for the registrant, and we have:
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(a)
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Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including their consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
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(b)
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[Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986];
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(c)
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Evaluated the effectiveness of the registrant’s disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant’s internal control
over financial reporting that occurred during the registrant’s most recent fiscal
quarter that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the registrant’s
auditors and the audit committee of registrant’s board of directors:
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(a)
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All significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control over
financial reporting.
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February 28, 2007
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/s/ William D. Rogers
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William D. Rogers
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Chief Financial Officer
Sierra Pacific Power Company
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Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
SIERRA PACIFIC RESOURCES
(“Registrant”)
In
connection with this report of Sierra Pacific Resources on Form 10-K for the fiscal year ended
December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, I,
Walter M. Higgins, III, Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. §
1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
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1.
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this report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
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2.
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the information contained in this report fairly presents, in all material respects, the
financial condition and results of operations of the registrant.
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/s/ Walter M. Higgins, III
Walter M. Higgins, III
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Chief Executive Officer
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Sierra Pacific Resources
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March 1, 2007
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This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed
filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as
amended, or otherwise subject to the liability of that section. Such certification will not be
deemed to be incorporated by reference into any filing under the Securities Act or the Exchange
Act, except to the extent the registrant specifically incorporates it by reference.
A signed original of this written statement required by Section 906 has been provided to the
registrant and will be retained by the registrant and furnished to the Securities and Exchange
Commission or its staff upon request.
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
NEVADA POWER COMPANY
(“Registrant”)
In
connection with this report of Nevada Power Company on Form 10-K for the fiscal year ended
December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, I,
Walter M. Higgins, III, Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. §
1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
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1.
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this report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
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2.
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the information contained in this report fairly presents, in all material respects, the
financial condition and results of operations of the registrant.
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/s/ Walter M. Higgins, III
Walter M. Higgins, III
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Chief Executive Officer
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Nevada Power Company
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March 1, 2007
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This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed
filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as
amended, or otherwise subject to the liability of that section. Such certification will not be
deemed to be incorporated by reference into any filing under the Securities Act or the Exchange
Act, except to the extent the registrant specifically incorporates it by reference.
A signed original of this written statement required by Section 906 has been provided to the
registrant and will be retained by the registrant and furnished to the Securities and Exchange
Commission or its staff upon request.
Exhibit 32.3
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
SIERRA PACIFIC POWER COMPANY
(“Registrant”)
In
connection with this report of Sierra Pacific Power Company on Form 10-K for the fiscal year
ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, I,
Walter M. Higgins, III, Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. §
1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
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1.
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this report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
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2.
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the information contained in this report fairly presents, in all material respects, the
financial condition and results of operations of the registrant.
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/s/ Walter M. Higgins, III
Walter M. Higgins, III
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Chief Executive Officer
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Sierra Pacific Power Company
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March 1, 2007
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This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed
filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as
amended, or otherwise subject to the liability of that section. Such certification will not be
deemed to be incorporated by reference into any filing under the Securities Act or the Exchange
Act, except to the extent the registrant specifically incorporates it by reference.
A signed original of this written statement required by Section 906 has been provided to the
registrant and will be retained by the registrant and furnished to the Securities and Exchange
Commission or its staff upon request.
Exhibit 32.4
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
SIERRA PACIFIC RESOURCES
(“Registrant”)
In
connection with this report of Sierra Pacific Resources on Form 10-K for the fiscal year ended
December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, I,
William D. Rogers, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as
adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
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1.
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this report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
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2.
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the information contained in this report fairly presents, in all material respects, the
financial condition and results of operations of the registrant.
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/s/ William D. Rogers
William D. Rogers
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Chief Financial Officer
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Sierra Pacific Resources
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March 1, 2007
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This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed
filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as
amended, or otherwise subject to the liability of that section. Such certification will not be
deemed to be incorporated by reference into any filing under the Securities Act or the Exchange
Act, except to the extent the registrant specifically incorporates it by reference.
A signed original of this written statement required by Section 906 has been provided to the
registrant and will be retained by the registrant and furnished to the Securities and Exchange
Commission or its staff upon request.
Exhibit 32.5
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
NEVADA POWER COMPANY
(“Registrant”)
In
connection with this report of Nevada Power Company on Form 10-K for the fiscal year ended
December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, I,
William D. Rogers, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as
adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
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1.
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this report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
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2.
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the information contained in this report fairly presents, in all material respects, the
financial condition and results of operations of the registrant.
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/s/ William D. Rogers
William D. Rogers
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Chief Financial Officer
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Nevada Power Company
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March 1, 2007
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This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed
filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as
amended, or otherwise subject to the liability of that section. Such certification will not be
deemed to be incorporated by reference into any filing under the Securities Act or the Exchange
Act, except to the extent the registrant specifically incorporates it by reference.
A signed original of this written statement required by Section 906 has been provided to the
registrant and will be retained by the registrant and furnished to the Securities and Exchange
Commission or its staff upon request.
Exhibit 32.6
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
SIERRA PACIFIC POWER COMPANY
(“Registrant”)
In
connection with this report of Sierra Pacific Power Company on Form 10-K for the fiscal year
ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, I,
William D. Rogers, Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as
adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
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1.
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this report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
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2.
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the information contained in this report fairly presents, in all material respects, the
financial condition and results of operations of the registrant.
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/s/ William D. Rogers
William D, Rogers
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Chief Financial Officer
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Sierra Pacific Power Company
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March 1, 2007
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This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed
filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as
amended, or otherwise subject to the liability of that section. Such certification will not be
deemed to be incorporated by reference into any filing under the Securities Act or the Exchange
Act, except to the extent the registrant specifically incorporates it by reference.
A signed original of this written statement required by Section 906 has been provided to the
registrant and will be retained by the registrant and furnished to the Securities and Exchange
Commission or its staff upon request.
