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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, 2001
Registrant, State of Incorporation, Address of
Commission File Principal Executive Offices and Telephone I.R.S. employer State of
Number Number Identification Number Incorporation
1-8788 SIERRA PACIFIC RESOURCES 88-0198358 Nevada
P.O. Box 10100 (6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
1-4698 NEVADA POWER COMPANY 88-0045330 Nevada
6226 West Sahara Avenue
Las Vegas, Nevada 89146
(702) 367-5000
0-508 SIERRA PACIFIC POWER COMPANY 88-0044418 Nevada
P.O. Box 10100 (6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
(Title of each class) (Name of exchange on which registered)
Securities registered pursuant to Section 12(b) of the Act:
Securities of Sierra Pacific Resources:
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Common Stock, $1.00 par value New York Stock Exchange
Common Stock Purchase Rights New York Stock Exchange
Securities of Nevada Power Company and subsidiaries:
----------------------------------------------------
8.2% Cumulative Quarterly Income New York Stock Exchange
Preferred Securities, Series A, issued by NVP Capital I
7 3/4% Cumulative Quarterly Trust Issued New York Stock Exchange
Preferred Securities, issued by NVP Capital III
Securities registered pursuant to Section 12(g) of the Act:
Securities of Sierra Pacific Power Company:
------------------------------------------
Class A Preferred Stock, Series I, $25 stated value
Indicate by check mark whether registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No ________
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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 Registrant's 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. X
-----
State the aggregate market value of the voting stock held by non-affiliates. As
of March 15, 2002: $ 1,665,622,642
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
March 15, 2002: 102,110,536 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 6, 2002, 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
ANNUAL REPORT ON FORM 10-K
CONTENTS
PART I ...................................................................................................... 3
Item 1. Business .......................................................................................... 3
Sierra Pacific Resources .... ............................................................................ 3
Nevada Power Company ........ ............................................................................ 5
Sierra Pacific Power Company ............................................................................. 14
Item 2. Properties ........................................................................................ 32
Item 3. Legal Proceedings ................................................................................. 33
Item 4. Submission Of Matters To A Vote Of Security Holders ............................................... 33
PART II ..................................................................................................... 34
Item 5. Market For The Registrant's Common Stock And Related Stockholder Matters .......................... 34
Item 6. Selected Financial Data ........................................................................... 36
Item 7. Management's Discussion And Analysis Of Financial Condition And Results Of Operations ............. 38
Sierra Pacific Resources ................................................................................. 43
Nevada Power Company ..................................................................................... 50
Sierra Pacific Power Company ............................................................................. 57
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ...................................... 79
Item 8. Financial Statements and Supplementary Data ....................................................... 82
Notes to Financial Statements ............................................................................ 100
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .............. 148
PART III .................................................................................................... 149
Item 10. Directors and Executive Officers of the Registrant .............................................. 149
Item 11. Executive compensation .......................................................................... 155
Item 12. Security Ownership of Certain Beneficial Owners and Management .................................. 161
Item 13. Certain Relationships and Related Transactions .................................................. 162
PART IV ..................................................................................................... 166
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ................................. 166
Signatures .................................................................................................. 168
2
FORWARD LOOKING STATEMENTS
The discussion of forward looking statements in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operation, is
incorporated herein by reference.
PART I
Item 1. BUSINESS
SIERRA PACIFIC RESOURCES
------------------------
Sierra Pacific Resources, hereafter known as SPR, was incorporated under
Nevada law on December 12, 1983. SPR's mailing address is P.O. Box 30150 (6100
Neil Road), Reno, Nevada 89520-3150 (89511).
SPR has eight primary, wholly owned subsidiaries: Nevada Power Company
(NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company
(TGPC), Sierra Pacific Communications (SPC), Sierra Energy Company, dba e. three
(e. three), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS) and
Nevada Electric Investment Company (NEICO). NPC and SPPC are referred to
together in this report as the "Utilities".
AN EXPLANATION OF THE REPORTING FORMAT
The merger between SPR and NPC on July 28, 1999 was treated for accounting
purposes as a reverse acquisition and deemed to have occurred on August 1, 1999.
As a result, for financial reporting and accounting purposes, NPC was considered
the acquiring entity under Accounting Principles Board Opinion No. 16, Business
Combinations, even though SPR became the legal parent of NPC. Because of this
accounting treatment, the financial information for the year ended December 31,
1999 reflects the acquisition of SPR by NPC on August 1, 1999. Therefore, the
results of operations for that year reflect twelve months of information for NPC
and five months of information for SPR and its pre-merger subsidiaries. This
presentation is carried forward to the notes to the financial statements.
The discussion in this report has been divided wherever possible to
highlight the activities of the major subsidiaries of SPR. Parenthetical
references are included after each major section title to identify the specific
entity addressed in the section. References to SPR refer to the consolidated
entity, except for the section related to debt financing in which SPR debt is
discussed separately from that of its subsidiaries.
INDUSTRY AND REGIONAL PROBLEMS AFFECTING The Utilities (NPC and SPPC)
---------------------------------------------------------------------
Electric Utility Trends
The year 2001 was challenging and unpredictable for the electric utility
industry, marked by volatile and uncharacteristic power prices, deterioration in
the credit quality of a number of utilities and power merchants, bankruptcy of a
major California utility and a major Houston based energy trading company, and
increased involvement and oversight by government and regulators.
Dramatic increases in wholesale power prices that began in 2000
continued into the first half of 2001, particularly in the West. Rolling
blackouts occurred in California. Wholesale energy prices in the West peaked in
the spring at levels up to four times what they were in the prior year. While
continuing blackouts and high power prices were predicted in the second half of
the year, they did not materialize. Instead, power prices moderated largely
because of mild weather across the United States, lower natural gas prices,
conservation in California, and the imposition by the FERC of federal price caps
in California and eleven western states,
3
including Nevada (see Regulation and Rate Proceedings, FERC Matters in Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations). Remaining as a result of this energy price volatility is a long
list of policy, regulatory, business and financial issues, many of which are
being addressed at both state and federal levels.
California continues to influence the region. In California, continued
high prices during the first half of the year and the lack of adequate rate
relief led to an inability to purchase energy, and credit problems and defaults
for the state's three largest utilities. In April 2001, Pacific Gas & Electric
Company filed for bankruptcy. The State of California took on the role of energy
buyer through its Department of Water Resources and funded billions of dollars
for short and long-term energy purchases which it plans to fund through the
issuance of bonds. While California's regulatory and policy issues are specific
to California, the state's problems exacerbated western energy problems and left
a mark throughout the region as western states continue to struggle with the
question of who should pay large fuel and purchased power balances.
Like other utilities in the West, the Utilities, which operate principally
in Nevada, have been significantly impacted by increased wholesale prices. High
fuel and power costs have led to large financing requirements, liquidity
constraints and depressed earnings. In Nevada, emergency legislation, Assembly
Bill (AB) 369, was enacted in April 2001 to control volatility in the price of
retail electricity in Nevada and to ensure the Utilities the financial resources
to provide adequate and reliable electric service. To achieve these purposes, AB
369 allows the Utilities to recover in future periods their costs for wholesale
power and fuel, subject to regulatory review for prudency. NPC filed for
recovery of deferred energy balances on December 1, 2001 and SPPC filed for
recovery of deferred energy balances on February 1, 2002. The businesses of SPR,
NPC, and SPPC are substantially dependent upon the outcomes of these
proceedings. See Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations for further legislative and regulatory
discussions. Also in December, the Utilities filed an action under Section 206
of the Federal Power Act seeking a rollback of wholesale power prices and
refunds.
High energy prices, power shortages, and a push at state and federal
levels for increased supply resulted in an unprecedented number of new power
plant project announcements nationally and in Nevada - mostly unregulated and
mostly natural gas-fired. Some power plants have been built or are under
construction. NPC is constructing transmission facilities to interconnect new
merchant plants being built in southern Nevada (see Nevada Power Company,
Transmission, for a discussion of the Centennial Plan). Towards year-end, a
weakening economy, lower demand, and a decline in energy prices have caused
power plant builders to reconsider planned projects. Some have announced
downsizings or cancellations. In addition, falling energy prices and pressure
from the major credit rating agencies have caused the announcement of a number
of asset sales.
In Nevada, the Utilities' divestiture of generation assets, which the PUCN
had previously ordered, was halted by the provisions of AB 369 that prohibit the
sale of generation assets until July 2003. Additionally, in April 2001, SPR and
Enron Corporation (Enron) mutually agreed to the termination of their agreement
for SPR's purchase of Enron's wholly owned subsidiary, Portland General Electric
(PGE), headquartered in Portland, Oregon.
National energy policy is also undergoing change due to the events of 2000
and 2001. The President's National Energy Policy Report was issued in May 2001.
Recently, Senate Bill (SB) 517 addressed the Public Utility Holding Company Act
(PUHCA) repeal and the Public Utility Regulatory Policies Act (PURPA) reform,
some FERC provisions, reliability, utility mergers, open access transmission,
net metering and interconnection. Senate action on the bill is pending.
4
Regulation and Electric Restructuring
The transition to retail competition continues to be highly uncertain,
driven by the development of a relatively young wholesale market and the
different approaches to retail competition taken by state regulators and
legislators. Rising wholesale prices, the western energy crisis, and the recent
bankruptcy filings of Pacific Gas & Electric Company and Enron have led many
states to review or revise restructuring plans.
While deregulation has been suspended in some states, in other states, the
process has slowed. In Nevada, AB 369, which became law in April 2001, repealed
all statutes authorizing retail competition in Nevada's electric utility
industry and voided any license issued to alternative sellers in connection with
retail competition. AB 661, passed in July 2001, enables large customers with
demand of one megawatt (MW) or more to choose a new energy supplier beginning
mid-2002 with permission from the PUCN upon meeting public interest tests.
Remaining committed to regional transmission organization development and
power competition, FERC plans to propose electric market design rules and issue
a final ruling by year-end 2002. Also, FERC recently approved the nation's first
regional transmission organization in the Midwest.
NEVADA POWER COMPANY
--------------------
NPC is a Nevada corporation organized in 1921. NPC became a wholly owned
subsidiary of SPR on July 28, 1999. Its mailing address is 6226 West Sahara
Avenue, Las Vegas, Nevada 89146.
NPC is a public utility engaged in the distribution, transmission,
generation, purchase and sale of electric energy in Clark County in southern
Nevada. It provides electricity to approximately 639,000 customers in the
communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and
adjoining areas. Service is also provided to Nellis Air Force Base and the
Department of Energy at Mercury and Jackass Flats at the Nevada Test Site.
Business and Competitive Environment
NPC's electric business contributed 100% of its 2001 operating revenues of
$3.025 billion. The system has an annual load factor of approximately 49.0%,
which is slightly lower than the industry norm of 50% to 55%.
Summer peak loads are driven by air conditioning demand. NPC's peak load
increased an average of 5.8% annually over the past five years, reaching 4,412
MW on July 2, 2001. NPC's total electric megawatt-hour (MWh) sales have
increased an average of 5.8% annually over the past five years. 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 service territory continues to be one of the fastest growing areas
in the nation. A significant part of the growth in NPC's electric sales has
resulted from new residential, industrial, and gaming customers.
NPC's electric customers by class contributed the following toward 2001
and 2000 MWh sales:
5
MWh Sales (Billed and Unbilled)
2001 2000
------------------------ -------------------------
Residential 7,208,540 25.5% 7,035,488 36.2%
Office 1,986,752 7.1% 1,896,111 9.7%
Gaming/Recreation/Restaurants 3,903,478 13.8% 3,963,286 20.4%
Wholesale 11,051,000 39.1% 2,675,484 13.8%
Other Retail 825,882 2.9% 783,467 4.0%
All Other & Unclassified 3,276,724 11.6% 3,101,564 15.9%
----------- ------ ------------ ------
TOTAL 28,252,376 100.0% 19,455,400 100.0%
=========== ====== ============ ======
Tourism and gaming remain southern Nevada's premier industries. Over 35
million tourists visited Las Vegas in 2001, infusing approximately $19.8 billion
into the local economy during the year. Currently, Las Vegas is the home of 18
of the world's 20 largest hotels. No mega-resort properties are scheduled to
open during 2002. Hotel room growth is expected to be just 0.8% during 2002.
The Las Vegas Convention Center has recently completed a $150 million
expansion project, adding 918,000 square feet of exhibit space and 90,000 square
feet of meeting space. The Las Vegas Convention Center now has more than 3.2
million square feet of total space, and features approximately 2 million square
feet of net exhibit space, and 380,000 square feet of net meeting room space,
accommodating 170 meeting rooms with seating capacities from 20 to 7,500. In
2001, more than 4.0 million convention and trade show delegates traveled to Las
Vegas, generating more than $4.8 billion in non-gaming revenue.
Shortly after the terrorist attacks of September 11, 2001, an estimated
12,000-15,000 gaming industry employees were laid off due to an expected
decrease in tourism revenue. In October 2001, many of these employees were
recalled, although some of them only on a part-time or on-call basis. Although
tourist traffic is not back to its previous levels, an upward trend has been
realized since early October 2001.
During 2001, firm and non-firm sales to wholesale customers comprised
39.1% of total energy sales, an increase of 310.0% over the prior year.
Wholesale customers consist of other utilities or municipalities that sell power
to end users, marketing entities and others that exchange power with NPC.
Wholesale MWh Sales
2001 2000
----------------------- ---------------------
Firm Sales 159,707 1.45% 283,480 10.52%
Non-Firm Sales 10,891,293 98.55% 2,412,442 89.48%
---------- ------ --------- ------
Total 11,051,000 100.00% 2,695,922 100.00%
========== ====== ========= ======
NPC's increase in wholesale MWh sales from last year was a result of
market conditions and NPC's power procurement activities. See Purchased Power
Procurement 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.
Construction Program
NPC's construction program and estimated expenditures are subject to
continuing review, and are revised from time to time due to various factors,
including the rate of load growth, escalation of construction
6
costs, availability of fuel types, the number and status of proposed independent
generation projects, the need for additional transmission capacity in southern
Nevada, changes in environmental regulations, adequacy of rate relief, and NPC's
ability to raise necessary capital.
Gross construction expenditures for 2001, including allowance for funds
used during construction (AFUDC) and contributions in aid of construction, were
200.9 million, and for the period 1997 through 2001, were $1,155.6 million.
Estimated construction expenditures for 2002 and the period from 2003 to 2006
are as follows (dollars in thousands):
2002 2003-2006 Total 5-Year
------------- ---------------- -----------------
Total construction expenditures $ 328,435 $ 862,661 1,191,096
AFUDC (8,699) (20,813) (29,512)
Net salvage, including cost of removal (1,034) (4,140) (5,174)
Net customer advances and
contributions in aid of construction (7,602) (30,408) (38,010)
------------- -------------- -------------
Total cash requirements $ 311,100 $ 807,300 1,118,400
============= ============== =============
Total construction expenditures estimated for 2002 and the 2003-2006
period consist of the following (dollars in thousands):
Total
2002 2003-2006 5-Year
-----------------------------------------------
Electric Facilities:
Distribution $128,436 $543,543 $ 671,979
Generation 26,027 53,392 79,419
Transmission 156,220 225,575 381,795
Other 17,752 40,151 57,903
---------------------------------------------
$328,435 $862,661 $1,191,096
=============================================
The River Mountain Project is a 230kV (kilovolt) joint transmission
project with the Colorado River Commission. Total project costs incurred through
December 31, 2001, were approximately $34.0 million. Actual costs for 2001 were
$7.7 million. This project was completed in 2001 and was in service in June of
2001.
The Centennial Plan was approved in NPC's 2001 Refiled Resource Plan.
This plan, consistent with its tariff and FERC pricing policies, involves the
following 500 kV lines (1) the Harry Allen substation to Crystal substation 500
kV lines, (2) the Harry Allen substation to Northwest substation 500 kV line,
and (3) the Harry Allen substation to Mead substation 500 kV line. Additional
facilities include a new 500 kV substation at Harry Allen, 500/230 kV
transformer at Mead and Northwest substation, phase shifting transformer at
Crystal substation, and several other sub-transmission upgrades and additions.
Total estimated cost of the project is $296.2 million. Total project actual
costs incurred through December 31, 2001, were $20.1 million. Estimated costs
for 2002 are $131.1 million, which may be financed utilizing internally
generated cash and/or the proceeds from various forms of debt. See Transmission,
later, for additional information about the Centennial Plan.
7
Facilities and Operations
Total System
NPC maintains a wide variety of resources in its generation system. 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. NPC also supplies
its customers' electric power needs using a combination of firm and
interruptible resources to maximize operating flexibility, while minimizing
cost. During 2001, NPC generated 33.9% of its total electric energy requirements
in its own plants, purchasing the remaining 66.1% as shown below:
Megawatt- Percent
Hours of Total
----------------- ---------------
NPC Company Generation
----------------------
Gas/Oil 4,206,728 14.4%
Coal 5,692,467 19.5%
----------------- ---------------
Total Generated 9,899,195 33.9%
----------------- ---------------
Purchased Power
---------------
Hydro 544,772 1.9%
Non-Firm Purchases 274,278 0.9%
Short Term Firm and Spot
Purchases 16,058,378 55.1%
Non-Utility Purchases 2,390,877 8.2%
----------------- ---------------
Total Purchased 19,268,305 66.1%
----------------- ---------------
Total 29,167,500 100.0%
================= ===============
NPC's decision to purchase short-term and spot energy in lieu of its own
generation is based on the economics of purchasing "as-available" energy when it
is less expensive than its own generation.
NPC's 2001 company generation of 9,899,195 MWh is down 7.9% from NPC's 2000
company generation of 10,744,466 MWh due to decreased generation late in 2001
when the cost of purchased power was more economical than generation. NPC's 2001
purchased power of 19,268,305 MWh is up 99.5% from NPC's 2000 purchased power of
9,659,118 MWh.
Risk Management
See Item 7A, Quantitative and Qualitative Disclosures About Market Risk.
Load and Resources Forecast
NPC's electric customer growth rate was 4.5% in 2001, 5.1% in 2000, and
5.9% in 1999. Retail electricity sales were 17.2 million MWh in 2001, which
represents an increase of 2.4% over 2000 retail electricity sales of 16.8
million MWh. Wholesale electricity sales reached 11.1 million MWh in 2001, which
represents an increase of 313% over 2000 wholesale electricity sales of 2.7
million MWh. Overall, annual system electricity sales reached 28.3 million MWh
in 2001, which represents an increase of 45% over 2000 system electricity sales
of 19.5 million MWh. The bulk of the 45% increase is attributed to wholesale
sales. Changes in the wholesale market have dramatically increased the amount of
purchases and sales of wholesale
8
power. See Purchased Power Procurement 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. NPC's peak electric
demand rose to 4,412 MW in 2001 from 4,325 MW in 2000.
The forecasted peak energy demand for 2002 and 2003 below reflects, among
others, five key assumptions:
. Southern Nevada experiences normal weather conditions, based on
historical 20-year averages.
. No adjustments have been made to incorporate the potential loss of
customers leaving for alternative providers under the provisions of
AB 661 or Senate Bill 211, which allows the Colorado River Commission
to sell electricity to its purveyors of water for water pumping
electric-related loads only. However, four large commercial customers
of NPC have filed an application under the provisions of AB 661 to
procure energy from an alternative source other than the Utility and
one large commercial customer has filed a letter of intent to file an
application to procure energy from an alternative source. The
combined peak load of AB 661 notice of intent customers and SB 211
eligible customers is less than 10% of NPC's retail load.
. Retail electric rates are set at the levels requested in NPC's most
recent general and deferred energy rate case filings.
. The southern Nevada economy recovers from the effects of the
September 11, 2001, terrorist attacks by the fourth quarter of 2002.
. Concerns over power outages in California subside by summer 2002
resulting in reduced conservation efforts by NPC's customers.
Sales and peak energy demand will vary from forecasted levels to the extent
that actual experience varies from the above assumptions and to the extent that
other factors affect sales and demand.
NPC's actual total system capability and peak loads for 2001, and as
estimated for summer peak demand for 2002 and 2003 are shown below:
9
Capacity at 2001 Peak Forecast Summer Peak (2)
------------------------------------------------------------------
MW % 2002 2003
------------------------------------------------------------------
NPC Company Generation:
Existing 1,559 32% 1,937 1,937
------------------------------------------------------------------
Purchases
Long/Short-Term Firm (1) 2,492 51% 2,022 1,572
Non-Utility Generators (2) 504 10% 515 515
Wholesale (3) (107) (2%) (114) (119)
------------------------------------------------------------------
Subtotal 2,889 59% 2,423 1,968
------------------------------------------------------------------
Additional Required (4) 449 9% 889 1,557
Total System Capacity 4,897 100% 5,249 5,462
==================================================================
Net System Peak (5) 4,412 90% 4,687 4,877
Planning Reserves 485 10% 562 585
------------------------------------------------------------------
Total Requirement 4,897 100% 5,249 5,462
==================================================================
Growth over previous year 7.2% 4.1%
(1) Long-term purchases include NPC's allotment of Hoover Dam energy. Values
are net of losses.
(2) Includes Sunpeak units.
(3) On peak wholesale commitment to Silver State Power Pool (SSPP). Generation
and purchases are reduced by the amount of load serving SSPP to show
remaining resources to meet the system peak.
(4) Includes potential short-term firm purchases that are not under contract.
Values shown represent purchases within existing transmission system
limits.
(5) The system peak shown for 2001 is the actual system peak of 4,412 MW, which
occurred on July 2, 2001.
NPC plans its system capacity needs in accordance with the Western Systems
Coordinating Council (WSCC) reliability criteria, which recommends planning
reserves in excess of required operating reserves. "Additional Required"
represents the additional, uncommitted capacity needed in order to maintain
adequate reserve margin consistent with the WSCC planning reserve criteria.
These additional reserves will be met, if needed, with short-term purchases
through 2003 to the extent available.
Generation
The following is a list of NPC's share of generation plants (except Reid
Gardner No. 4, see note (2) below), including the MW summer net capacity, the
type and fuel used to generate, and the year(s) that the unit(s) was (were)
installed.
10
Number of MW
Name Type Fuel Units Capacity Years(s) Installed
-----------------------------------------------------------------------------------------------------------
Clark Station Steam Gas/Oil 3 175 1955, 1957, 1961
Combustion Turbine Gas/Oil 1 50 1973
Combined Cycles (1) Gas/Oil 6 462 1979, 1979, 1980, 1982,
1993, 1994
-----------------------
Total Clark Station 10 687
Reid Gardner (2) Steam Coal 4 605 1965, 1968, 1976, 1983
Navajo (3) Steam Coal 3 255 1974
Mohave (4) Steam Coal 2 196 1971
Sunrise Steam Gas/Oil 1 80 1964
Combustion Turbine Gas/Oil 1 69 1974
-----------------------
Total Sunrise 2 149
-----------------------
Harry Allen Combustion Turbine Gas/Oil 1 72 1995
-----------------------
Grand Total NPC 22 1964
=======================
(1) The combined cycles at Clark Station each consist of one steam turbine
and two combustion turbines for a total of six generating units.
(2) Reid Gardner Unit No. 4 is jointly owned by the California Department
of Water Resources ("CDWR") (67.8%) and NPC (32.2%). NPC is the
operating agent. Contractually, NPC is entitled to receive 24 MW of
base load capacity and 226 MW of peaking capacity. NPC is entitled to
use 100% of the unit's peaking capacity for 1,500 hours each year and
is entitled to 9.6% of the first 250 MW of capacity and associated
energy.
(3) This represents NPC's 11.3% undivided interest in the Navajo Generating
Station as tenant in common without right of partition with five other
non-affiliated utilities.
(4) This represents NPC's 14% undivided interest in the Mohave Generating
Station as tenant in common without right of partition with three other
non-affiliated utilities, less operating restrictions.
Purchased Power
NPC utilizes and maintains a diverse portfolio of resources with the
objective of minimizing its net average system operating costs while providing
reliable service. This portfolio consists of contracted and spot market
supplies, as well as its own generation. During the past several years,
including the first half of 2001, NPC experienced a dramatic increase in the
market price of energy. Some of this increase reflects an overall increase in
electricity costs throughout the country, the changing of regulatory
environments, and the opening of new and/or deregulated markets. However, costs
for contracted and spot market energy supplies fell dramatically in the second
half of 2001 and limited NPC's ability to mitigate previous purchase power costs
by selling any short-term excess energy because it limited the price at which
NPC could sell surplus energy during market shortages. Some of NPC's purchased
power contracts are also at price levels above which NPC is permitted to recover
in current rates. See Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations, for a discussion of deferred
energy accounting and legislation.
NPC is a member of the Western Systems Power Pool 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.
NPC purchases both forward firm energy (typically in blocks) 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.
11
NPC purchases Hoover Dam power pursuant to a contract with the State of
Nevada which became effective June 1, 1987, and will continue through September
30, 2017. NPC's allocation of hydro-electric capacity is 235 MW.
NPC has a contract to purchase 222 MW from Nevada Sunpeak Limited
Partnership, an independent power producer. The contract became effective June
8, 1991 and will continue through May 31, 2016.
According to the regulations of the PURPA, NPC is obligated, under certain
conditions, to purchase the generation produced by small power producers and
cogeneration facilities at costs determined by the appropriate state utility
commission. Generation facilities that meet the specifications of the
regulations are known as qualifying facilities (QFs). As of December 31, 2001,
NPC had a total of 305 MW of contractual firm capacity under contract with four
QFs. All QF contracts currently delivering power to NPC at long-term rates have
been approved by the PUCN and have QF status as approved by the FERC. The QFs
are as follows:
Net
Qualifying Facility Contract Contract Capacity
Start End (MW)
- -----------------------------------------------------------------
Saguaro Power Company 10/17/91 04/30/22 90
Nevada Cogeneration
Associates #1 06/18/92 04/30/23 85
Nevada Cogeneration
Associates #2 02/01/93 04/30/23 85
Las Vegas Cogeneration
Limited Partnership 05/10/94 05/31/24 45
------------
Total 305
============
Energy purchased by NPC from the QFs constituted 29.1% of the net purchased
power requirements (excluding wholesale purchases), and 13.2% of the net system
requirements during 2001. All of the QFs are cogenerators providing steam for
various products and businesses.
Transmission
NPC's existing transmission lines are primarily confined within Clark
County, Nevada. Four 230kV transmission lines connect NPC to the Western Area
Power Administration's transmission facilities at Henderson and Mead
Substations. Three 230 kV lines connect NPC to the Los Angeles Department of
Water and Power's transmission facilities at McCullough Substation. A 345 kV
line connects NPC to PacifiCorp at the Utah-Nevada state line. Also, NPC has two
500/230 kV transformers that connect NPC to the Navajo Transmission System at
the Crystal Substation. Finally, NPC also has ownership rights in two 500 kV
transmission lines that allow for the transmittal of NPC's share of power from
its interests in the Mohave and Navajo Generating Stations to NPC's systems.
The River Mountain Project is a transmission project developed in
partnership with the Colorado River Commission of Nevada that was placed in
service in June 2001. NPC's portion of the project consists of two 230 kV
transmission lines built along separate transmission corridors between the Mead
Substation and NPC's new Equestrian Substation. In addition, to facilitate the
ability to deliver power scheduled between Mead Substation and Equestrian
Substation, NPC built a 230 kV transmission line between the Equestrian
Substation and the Faulkner Substation. The project increased import capability
by 350 MW. The completed project costs were approximately $34.0 million.
12
NPC received approval from the PUCN to construct two transmission projects
proposed in NPC's 2001 Refiled Resource Plan. The Faulkner Substation to Tolson
Substation 230 kV project and the Tolson Substation to Arden Substation 230 kV
upgrade project are both internal, NPC reinforcements with 2003 and 2004
in-service dates, respectively. Due to independent power producer (IPP)
transmission service requests, the Arden-Tolson 230 kV upgrade project will be
advanced one year for an in-service date of June 2003. The Faulkner-Tolson 230
kV project will increase NPC's import capability by 300 MW. The total estimated
project costs are $8.29 million.
Due to the supply shortage in the western United States, several IPP's have
proposed the construction of new generating plants in southern Nevada, and have
requested transmission service from NPC. NPC has committed to construct this
transmission infrastructure in furtherance of its on-going business plan. NPC
has proposed the Centennial Plan to address transmission service requests from
these IPP's. The Centennial Plan was approved in NPC's 2001 Refiled Resource
Plan. This plan, consistent with its tariff and FERC pricing policies, involves
the following lines (1) the Harry Allen substation to Crystal substation 500 kV
line, (2) the Harry Allen substation to Northwest substation 500 kV line, (3)
the Harry Allen substation to Mead substation 500 kV line and (4) Two
Bighorn-Arden 230 kV lines. Additional facilities include a new 500 kV
substation at Harry Allen, 500/230 kV transformers at Mead and Northwest
substation, a phase shifting transformer at Crystal substation, and several
other sub-transmission upgrades and additions.
See Regulation and Rate Proceedings, FERC Matters in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations for a
discussion of regional transmission issues.
Fuel Availability
NPC's 2001 fuel requirements for electric generation were provided by
natural gas, coal and oil. The average costs of coal, gas and oil for energy
generation per million British thermal units (MMBtu) for the years 1997 - 2001,
along with the percentage contribution to total fuel requirements were as
follows:
-----------------------------------------------------------------------------
Average Consumption Cost & Percentage Contribution to Total Fuel Requirements
Gas Coal Oil
--- ---- ---
$/MMBtu Percent $/MMBtu Percent $/MMBtu Percent
------- ------- ------- ------- ------- -------
2001 5.34 42.6% 1.26 57.3% 7.14 0.1%
2000 4.93 42.6% 1.22 57.2% 7.33 0.1%
1999 2.27 40.6% 1.15 59.3% 4.01 0.1%
1998 2.35 33.0% 1.39 67.0% 3.96 *
1997 2.25 33.0% 1.39 67.0% 3.35 *
* Oil was less than .1% of consumption
-----------------------------------------------------------------------------
For a discussion of the change in fuel costs, see Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Coal delivered to the Reid Gardner Station originates from various mines in
the Utah coalfields and is delivered to the station via the Union Pacific
Railroad. Partial requirements for coal supplies are under contract for various
terms up to 2007, with the remainder of 2001's requirements purchased from the
spot market under four one-year contracts. NPC's long-term coal supply agreement
with RAG Coal Sales of America, Inc. is supplied from its Willow Creek Mine in
Carbon County, Utah, which experienced an explosion and fire on July 31, 2000,
and is currently under an ongoing force majeure. No deliveries under this
agreement were scheduled for 2001 and NPC replaced these volumes with spot
market purchases.
13
The mine remains sealed and NPC does not anticipate that deliveries will resume
before the contract terminates.
The Union Pacific Rail Transportation contract provides for deliveries from
the Provo, Utah interchange as well as various mines in the Price, Utah area to
the Reid Gardner Station in Moapa, Nevada. This contract was effective January
1, 1996 and has been extended through December 31, 2004. The Utah Railway
contract originates the remainder of NPC's Price, Utah area supplies. This
contract has been extended through December 31, 2002. All of NPC's rail
transportation contracts contain certain tonnage requirements and railroad
service criteria.
Coal for both the Mohave and Navajo Stations is obtained from surface
mining operations conducted by Peabody Coal Company on portions of the Black
Mesa in Arizona within the Navajo and Hopi Indian reservations. The supply
contracts with Peabody extend to December 31, 2005 for Mohave and to June 1,
2011 for Navajo, each contract having an option to extend for an additional 15
years.
NPC purchases natural gas on a firm, fixed and indexed price basis from the
Rocky Mountain, San Juan or Permian Supply Basins.
Natural gas is transported to the Clark and Sunrise stations via El Paso
Natural Gas Company from the San Juan and Permian Basins and by Kern River Gas
Transmission Company from the Rocky Mountain Basin. NPC has entered into a
summer seasonal transportation contract for 50,000 decatherms (Dth)/day and an
annual contract for 75,000 Dth/day of Kern River Pipeline capacity. This service
is scheduled for delivery in May 2003 and will run for a period of 15 years. NPC
also responded to an open season for shorter term service in the Kern River
California Emergency Expansion and was awarded 29,600 Dth/day for the period
July 2001 to April 2002 and 5,600 Dth/day for the period May 2002 to April 2003.
The Emergency Expansion service does not carry any renewal rights.
Local natural gas transportation service to Clark and Sunrise Stations is
provided under a 32-year transportation services contract with Southwest Gas
Company signed in 1995. This contact provides firm service and contains certain
operating and nominating provisions. The Harry Allen Station is directly
connected to Kern River Pipeline.
Oil provides a secondary fuel for Clark, Sunrise and Harry Allen Stations
and is used in the igniters at Reid Gardner.
Regulation and Rate Proceedings
See Regulation and Rate Proceedings in Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations.
SIERRA PACIFIC POWER COMPANY
----------------------------
SPPC is a Nevada corporation organized in 1965 as a successor to a Maine
corporation organized in 1912. SPPC became a wholly owned subsidiary of Sierra
Pacific Resources on May 31, 1984. Its mailing address is Post Office Box 10100
(6100 Neil Road), Reno, Nevada 89520-0024.
SPPC is a public utility primarily engaged in the distribution,
transmission, generation, purchase and sale of electric energy. It provides
electricity to approximately 315,000 customers in a 50,000 square mile service
area in western, central and northeastern Nevada, including the cities of Reno,
Sparks, Carson City, Elko, and a portion of eastern California, including the
Lake Tahoe area. In 2001, electric revenues were 90.6% of SPPC's revenue.
14
SPPC also provides natural gas service in Nevada to approximately 119,500
customers in an area of about 600 square miles in Reno/Sparks and environs. In
2001, natural gas revenues were 9.4% of SPPC's revenues.
On June 11, 2001, SPPC completed the sale of its water business to the
Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8
million gain on the sale, net of income taxes of $18.2 million. Transfer of the
hydroelectric facilities included in the contract of sale for an additional $8
million will require action by the California Public Utility Commission (CPUC).
The sale agreement contemplates a second closing for the hydroelectric
facilities to accommodate the CPUC's review of the transaction. See "Sale of
Water Business," later, for further discussion.
SPPC has three primary, wholly owned subsidiaries: GPSF-B, Pinon Pine Corp.
(PPC) and Pinon Pine Investment Co. (PPIC). GPSF-B, PPC and PPIC, collectively,
own Pinon Pine Company, L.L.C., which was formed to take advantage of federal
income tax credits available under (S)29 of the Internal Revenue Code associated
with the alternative fuel (syngas) produced by the coal gasifier located at the
Pinon Pine facility. (See Note 5 to the Financial Statements.)
Business and Competitive Environment
In 2001, SPPC's electric business contributed $1,399 million (90.6%) in
revenues from continuing operations. The electric system peak typically occurs
in the summer, while the winter peak runs nearly as high. The system has an
annual load factor of approximately 71%, which is higher than the industry norm
of 50% to 55%.
Winter peak loads are primarily driven by increased demand for space
heating, demand for air movement (with forced air gas and oil furnaces), and ski
resort demands (hotels, lifts, etc.). Summer peak loads are primarily driven by
cooling equipment demand (including air conditioning demand) and irrigation
pumping. SPPC's peak load increased an average of 4.6% annually over the past
five years, reaching 1,529 MW on August 7, 2001. SPPC's total electric MWh sales
have increased an average of 10.3% annually over the past five years. The mining
and wholesale sectors comprise the majority of this growth.
SPPC's electric customers by class contributed the following toward 2001
and 2000 MWh sales:
MWh Sales
2001 2000
-------------------------- ----------------------------
Residential 2,069,140 16.1% 2,042,704 16.4%
Commercial and Industrial:
Mining 2,662,763 20.7% 2,720,018 21.9%
Offices/Schools/Government 1,141,861 8.9% 1,108,988 8.9%
Resorts & Recreation 689,861 5.4% 780,526 6.3%
Manufacturing/Warehouse 769,053 5.9% 795,728 6.4%
Wholesale 4,123,513 32.1% 3,613,996 29.1%
All Other 1,408,456 10.9% 1,372,701 11.0%
----------- ------ ------------ ------
Total 12,864,647 100.0% 12,434,661 100.0%
=========== ====== ============ ======
According to the Nevada Division of Minerals, the State led the nation in
the production of gold in 2001, as it has for many years. Nevada's gold
production in 2001 reached 8.1 million ounces. However, in 2001 the industry
continued to be challenged by low gold prices and numerous financial,
environmental, and regulatory hurdles. It responded to these pressures by
continuing to pursue mergers and consolidations, streamlining
15
operations, cutting overhead costs, and closing down less efficient and
uneconomic properties. These actions led to SPPC seeing a small decrease in
total MWh sales to the mining industry during 2001.
SPPC has long-term power sales agreements with seven of its major mining
customers for terms ranging from 5 to 15 years. The final contract expires in
2011. These agreements secure over 265 MW of present and future mining load, or
approximately $96 million in annual revenues, which is 6.9% of 2001 electric
operating revenues. The agreements require that customers maintain minimum
demand and load factor levels, and include termination charge provisions to
recover all of SPPC's customer-specific facilities investment.
The resorts and recreation customer segment consists of hotels, casinos and
ski resorts which comprise 5.4% of the total electric system retail MWh sales.
Overall MWh sales are slightly down from 2000 due to implementation of energy
conservation efforts at most of the large casino hotels and a winter that has
provided an increase in precipitation. The snowfall has decreased the need for
the ski resorts to use their snowmaking equipment which is a large component of
their energy consumption.
Tourism and gaming were affected by the decrease in flight schedules and
the economy downturn last September. Northern Nevada casinos have also seen some
impact from Indian gaming in northern California. Though the tourism and gaming
segment faced challenges in 2001, northern Nevada continues to be a strong
player in the entertainment industry. Northern Nevada casino hotels are
continuously focusing on competitive strategies by packaging entertainment
value, customer comfort and reasonable pricing with the natural attraction of
the Sierra Nevada geographical location which has proven to be a successful
model. Many of the larger casinos have also remodeled their facilities to
provide for an increased demand for conventions.
The manufacturing and warehousing customer segment overall continues to
grow at a steady pace. Several manufacturing customers have suffered large order
reductions and production losses due to the economic slowdown, which has had an
impact on the rapid growth projections. At the same time, there has been growth
in the sector as the result of manufacturers relocating out of the California
market and expanding their Nevada presence. Northern Nevada continues to show
promise as a destination of choice for the high-technology industry, which
should result in a continued increase in sales to the manufacturing and
warehousing customer segment. In 2001, SPPC solidified working relationships
within the business community recruiting industries in targeted sectors such as
plastic manufacturers and hi-technology companies.
The 2001 session of the Nevada State legislature saw the passage of AB 661.
One provision of this bill allows commercial customers with an average annual
load of one megawatt or more to file a letter of intent and application with the
PUCN to buy electricity from another provider beginning in mid-2002. This
provision was part of a package of legislation passed by the 2001 Legislature to
ensure the continued creditworthiness of the Utilities and protect consumers
from unexpected rate hikes. During 2001, a number of SPPC's large commercial
customers indicated they would be filing applications to pursue alternative
supplier options. See Regulation and Rate Proceedings in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations for
further discussion.
SPPC's MWh sales to wholesale customers have increased 14.1% over the past
year. During 2001, firm and non-firm sales to wholesale customers comprised
32.1% of total energy sales. Wholesale customers consist of other utilities or
municipalities that sell power to end users, marketing entities and others that
exchange power with SPPC.
16
Wholesale MWh Sales
2001 2000
--------------------------- ---------------------------
Firm Sales 4,085,097 99.1% 3,365,783 93.1%
Non-Firm Sales 38,416 0.9% 248,213 6.9%
---------- ------ ---------- ------
Total 4,123,513 100.0% 3,613,996 100.0%
========== ====== ========== ======
SPPC's increase in wholesale MWh sales from last year was a result of
market conditions and SPPC's power procurement activities. See Purchased Power
Procurement 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.
Construction Program
SPPC's construction program and estimated expenditures are subject to
continuing review, and are revised from time to time due to various factors,
including 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, changes in environmental regulations, adequacy of rate relief, and
SPPC's ability to raise necessary capital.
Gross construction expenditures for 2001, including AFUDC and contributions
in aid of construction, were $133.6 million, and for the period 1997 through
2001, were $762.4 million. Estimated construction expenditures for 2002 and the
period 2003-2006 are as follows (dollars in thousands):
Total
2002 2003-2006 5-Year
---------------------------------------------
Electric facilities $ 132,875 $ 382,096 $ 514,971
Gas facilities 9,751 48,420 58,171
Common facilities 6,669 26,660 33,329
---------------------------------------------
Total construction expenditures 149,295 457,176 606,471
---------------------------------------------
AFUDC (5,682) (15,056) (20,738)
Net salvage, including cost of removal (120) (400) (520)
Net customer advances and
contributions in aid of construction (3,942) (15,320) (19,262)
---------------------------------------------
Total cash requirements $ 139,551 $ 426,400 $ 565,951
=============================================
Total construction expenditures estimated for 2002 and the 2003-2006
period, for each segment of SPPC's business, consist of the following (dollars
in thousands):
17
Total
2002 2003-2006 5-Year
---- --------- ------
Electric Facilities:
Distribution $ 48,386 $ 256,387 $ 304,773
Generation 5,335 21,100 26,435
Transmission 69,709 83,599 153,308
Other 9,445 21,010 30,455
------------------------------------------
132,875 382,096 514,971
------------------------------------------
Gas Facilities:
Distribution 8,819 44,680 53,499
Other 932 3,740 4,672
------------------------------------------
9,751 48,420 58,171
------------------------------------------
Common Facilities 6,669 26,660 33,329
------------------------------------------
TOTAL $ 149,295 $ 457,176 $ 606,471
==========================================
The Falcon to Gonder Transmission Project is a 345kV transmission line
within northern Nevada with a planned in-service date of June 2003. Total
project costs incurred through December 31, 2001, were $11.5 million. Actual
costs incurred in 2001 were $5.9 million. Estimated costs for 2002 are $54.5
million.
Facilities and Operations
Total System
SPPC maintains a wide variety of resources in its generation system. 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. SPPC also supplies
its customers' electric power needs using a combination of firm and
interruptible resources to maximize operating flexibility and reliability, while
minimizing cost. During 2001, SPPC generated 44.6% of its total electric energy
requirements in its own plants, purchasing the remaining 55.4% as shown below:
18
Megawatt- Percent
Hours of Total
----------- ----------
SPPC Company Generation
-----------------------
Gas/Oil 4,090,757 30.3%
Coal 1,870,909 13.9%
Hydro 50,993 0.4%
----------- --------
Total Generated 6,012,659 44.6%
----------- --------
Purchased Power
---------------
Utility Purchases:
Long-Term Firm 454,589 3.4%
Short-Term Firm 6,164,555 45.7%
Spot Market 30,910 .2%
Non-Utility Purchases:
Geothermal 702,616 5.2%
Other 125,988 .9%
Transmission & Balancing 5,071 0.0%
----------- --------
Total Purchased 7,483,729 55.4%
----------- --------
Total 13,496,388 100.0%
=========== ========
As a supplement to its own internal generation, SPPC purchases both firm
and non-firm energy to meet its customer demand requirements. See Purchased
Power Procurement 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. In 2001, most of SPPC's non-utility
generation came from QFs, except for 21,730 MWh, which came from two small power
producers.
Risk Management
See Item 7A, Quantitative and Qualitative Disclosures About Market Risk.
Load and Resources Forecast
SPPC's electric customer growth rate was 1.9% in 2001, 2.6% in 2000, and
2.6% in 1999. Annual retail electricity sales were 8.7 million MWh in 2001,
which represents a decrease of 1% compared to 2000 retail electricity sales of
8.8 million MWh. Annual wholesale electricity sales reached 4.1 million MWh in
2001, which represents an increase of 14% over 2000 wholesale electricity sales
of 3.6 million MWh. Overall, annual system electricity sales reached 12.9
million MWh in 2001, which represents an increase of 3.5% over 2000 system
electricity sales of 12.4 million MWh. The 2001 peak electric demand was 1,529
MW compared to a weather-adjusted peak of 1,531 MW for 2000. The lack of growth
in the peak is mainly attributable to demand-reduction efforts by customers due
to the power issues in the West.
The forecasted peak energy demand for 2002 and 2003 below reflects, among
others, five key assumptions:
. Northern Nevada experiences normal weather conditions, based on
historical 20-year averages.
. No adjustments have been made to incorporate the potential loss of
customers leaving for alternative providers under the provisions of
AB661. However, one large commercial customer of SPPC has filed an
application under the provisions of AB 661 to procure energy from an
alternative source other than the Utility. The customer, SPPC, and
PUCN staff are negotiating a stipulation regarding settlement of the
terms and conditions under which this customer will be permitted to
procure energy from an alternative source other than SPPC. The terms
and conditions of the stipulation are expected to comply with the
provisions of AB 661 in that SPPC and
19
its remaining customers will not be negatively impacted by the
customer's departure. A hearing on the stipulation has been set for
March 20, 2002.
. Retail electric rates are set at the levels requested in SPPC's most
recent general and deferred energy rate case filings.
. SPPC continues to be a summer peaking utility.
. Concerns over power outages in California subside by summer 2002
resulting in reduced conservation efforts by SPPC's customers.
Sales and peak energy demand will vary from forecasted levels to the extent
that actual experience varies from the above assumptions and to the extent that
other factors affect sales and demand.
SPPC's actual total system capability and peak loads for 2001, and as
estimated for summer peak demand for 2002 and 2003 are shown below:
Capacity at 2001 Peak Forecast Summer Peak
-----------------------------------------------------
MW % 2002 2003
-----------------------------------------------------
SPPC Company Generation:
Existing (1) 1,026 58% 1,045 1,062
-----------------------------------------------------
Purchases:
Long/Short-Term Firm (2) 475 27% 500 525
Interruptible/Wheeling/Losses (3) 176 10% 5 7
Non-Utility Generators 93 5% 85 85
-----------------------------------------------------
Subtotal 744 42% 590 617
-----------------------------------------------------
Additional Required 0 0% 176 165
Total System Capacity 1,770 100% 1,811 1,844
=====================================================
Net System Peak Demand (4) 1,529 90% 1,621 1,654
Planning Reserve 177 10% 190 190
-----------------------------------------------------
Total Requirement 1,706 100% 1,811 1,844
=====================================================
Growth over previous year 6.2% 1.8%
(1) The Clark Mountain Gas Turbine (G.T.) and Winnemucca G.T. were both
unavailable during the time of the 2001 system peak. Assumes Pinon
Pine duct burner modification occurs in the fall 2002, adding 17 MW of
net capacity.
(2) Value is net of losses and includes committed short-term firm block
purchases. Values shown represent purchases within existing
transmission system limits. No economy (non-firm) energy purchases
(only firm power purchases) occurred during the 2001 peak.
(3) Includes net wheeling from the Naniwa power station during the 2001
peak of 132 MW, which was retained in SPPC's system.
(4) The system peak shown for 2001 occurred on August 7, 2001, at 5:00
p.m.
SPPC plans its system capacity needs in accordance with the WSCC
reliability criteria, which recommends planning reserves in excess of required
operating reserves. "Additional Required" represents the additional, uncommitted
capacity needed in order to maintain adequate reserve margin consistent with the
WSCC planning reserve criteria. These additional reserves will be met, if
needed, with short-term purchases through 2003 to the extent available. At the
time of the 2001 system peak, SPPC had purchased firm capacity
20
under long-term contracts with other utilities and qualifying facilities equal
to 10% of total peak hour capacity. Short-term firm block purchases comprised
26% of the peak, with no economy (non-firm) purchases transacted (only firm
power purchases).
Generation
The following is a list of SPPC's share of generation plants including the
MW summer net capacity, the type and fuel used to generate, and the year(s) that
the unit(s) was (were) installed.
Number of MW
Name Type Fuel Units Capacity Years(s) Installed
-----------------------------------------------------------------------------------------------------------------------
Valmy (1) Steam Coal 2 266 1981, 1985
Tracy Steam Gas/Oil 3 244 1963, 1965, 1975
Pinon (2) Combined Cycle (3) Gas 1 89 1996
Clark Mtn. CT's Combustion Turbine Gas/Oil 2 138 1994
Ft. Churchill Steam Gas/Oil 2 226 1968, 1971
Other (4) Gas Turbine, Hydro Gas/Oil, Propane 33 82 1899-1970
-------- ----------
Grand Total SPPC 43 1045
======== ==========
(1) SPPC is the operator and owns an undivided 50 percent interest in the
Valmy plant. Idaho Power Company owns the remainder. The capacities
shown above for the Valmy plant represent SPPC's share only. SPPC owns
100 percent of all of its remaining electric generation plants.
(2) Pinon is part of the Pinon Pine Integrated Coal Gasification Combined
Cycle power plant. This project was part of the Department of Energy's
Clean Coal Demonstration Program. Although the coal gasification
portion of the facility is in the start-up phase, the unit has been
operating on natural gas since 1996.
(3) The combined cycle at Pinon consists of one combustion turbine and one
steam turbine.
(4) The 4 hydro generating units were to be included in the sale of SPPC's
water business in June 2001. However, the California Legislature has
mandated that the sale of these units (as well as any other units
serving California markets) be postponed until 2006 due to uncertainty
in the California power markets. See sale of Water Business, later.
Purchased Power
SPPC 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 2001, SPPC experienced a dramatic
increase in the price of market energy compared to previous years. Some of this
increase is reflective of the overall increase in electricity costs throughout
the western United States. See Industry and Regional Problems Affecting the
Utilities, earlier. Some of SPPC's purchased power contracts are at price levels
above which SPPC is permitted to recover in current rates. See Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations, for a discussion of deferred energy accounting and legislation.
SPPC is a member of the Northwest Power Pool and Western Systems Power
Pool. These pools have provided SPPC further access to spot market power in the
Pacific Northwest and the Southwest. In turn, SPPC's generation facilities
provide a backup source for other pool members who rely heavily on hydroelectric
systems.
SPPC purchases hydroelectric and thermal generation spot market energy, by
the hour, based upon economics and system import limits. Also purchased during
peak load periods is firm energy as required to supply load and maintain
adequate operating reserve margins. As off-system energy costs increase, SPPC
21
supplies a higher percentage of its native load utilizing its fossil fuel
generation but is still required to buy peaking energy from the market.
Currently, SPPC has contracted for a total of 75 MW of long-term firm
purchased power from the utility supplier listed below. SPPC's firm purchase
power contract contains minimum purchase obligations. Meeting these minimums has
not been a problem for SPPC in the past, and is not expected to be a problem in
the future.
Contract Operation Termination Minimum
Contract Party Capacity Date Date Capacity
------------------------------------------------------------------------------------
PacifiCorp 75 MW June 1989 Feb 28, 2009 70%
According to PURPA, SPPC is obligated, under certain conditions, to
purchase the generation produced by small power producers and co-generation
facilities at costs determined by the appropriate state utility commission.
Generation facilities that meet the specifications of the regulations are known
as qualifying facilities. As of December 31, 2001, SPPC had a total of 109 MW of
maximum contractual firm capacity under 15 contracts with QFs. SPPC also had
contracts with three projects at variable short-term avoided cost rates. All QF
contracts currently delivering power to SPPC at long-term rates have been
approved by either the PUCN or the California Public Utility Commission (CPUC),
and have QF status as approved by the FERC. One long-term QF contract terminates
in 2006, one terminates in 2039, and the rest terminate between 2014 and 2022.
Energy purchased by SPPC from QFs constituted 8.8% of the net system
requirements (excluding wholesale purchases) during 2001. These contracts
continue to provide useful diversity for SPPC in meeting its peak load. All the
QFs from which SPPC makes firm purchases are either geothermal (87%),
hydroelectric or biomass.
The actual QF firm capacity output under contract was 64 MW during the
summer of 2001. The actual QF output for all non-utility generator deliveries
during the summer 2001 peak was 93 MW
Transmission
SPPC's existing transmission lines extend some 300 miles from the crest of
the Sierra Nevada in eastern California, northeast to the Nevada-Idaho border at
Jackpot, Nevada, about 160 miles from Reno northwest to Alturas, California, and
250 miles from the Reno area south to Tonopah, Nevada. A 230 kV transmission
line connects SPPC to facilities near the Utah-Nevada state line, which in turn
interconnects SPPC to Utah Power facilities. A 345 kV transmission line connects
SPPC to Idaho Power facilities at the Idaho-Nevada state line. A 345 kV line
connects SPPC to the Bonneville Power Administration's facilities near Alturas,
California.
SPPC also has two 120 kV lines and one 60 kV line that interconnect with
Pacific Gas & Electric on the west side of SPPC's system at Donner Summit,
California. Two 60 kV transmission ties allow wheeling of up to 14 MW of power
from the Beowawe Geothermal Project, which is located within SPPC's service
area, to Southern California Edison. These two minor interties are available for
use during emergency conditions affecting either party. The transmission
intertie system provides access to regional energy sources.
The Falcon to Gonder Project is a 185-mile 345 kV line connecting SPPC's
Falcon Substation to Mt. Wheeler Power's Gonder Substation. The Falcon to Gonder
Project improves system import and export capabilities and enables SPPC to
provide transmission service between Idaho, Utah, and the northwest. The Final
Environmental Impact Statement was released in December 2001. Federal permitting
is expected to be completed by the end of March 2002, with construction starting
in May 2002. SPPC has ordered long lead material like towers and transformers,
and is preparing to start the construction bid process. The project in-
22
service date is June 2003. Total project costs incurred through December 31,
2001, were $11.5 million. Actual costs incurred in 2001 were $5.9 million.
Estimated costs for 2002 are $54.5 million.
See Regulation and Rate Proceedings, FERC Matters in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations for a
discussion of regional transmission issues.
Fuel Availability
SPPC's 2001 fuel requirements for electric generation were provided by
natural gas, coal, and oil. The average costs of coal, gas and oil for energy
generation per MMBtu for the years 1997-2001, along with the percentage
contribution to total fuel requirements, are as follows:
------------------------------------------------------------------------------------------
Average Consumption Cost & Percentage Contribution to Total Fuel Requirements
Gas Coal Oil
--- ---- ---
$/MMBtu Percent $/MMBtu Percent $/MMBtu Percent
------- ------- ------- ------- ------- -------
2001 5.63 45.3% 1.55 32.4% 6.49 22.3%
2000 4.99 66.6% 1.51 32.2% 7.62 1.2%
1999 2.71 62.3% 1.46 37.3% 3.41 0.4%
1998 2.12 60.7% 1.56 39.0% 3.96 0.3%
1997 2.03 62.0% 1.80 37.0% 3.35 1.0%
------------------------------------------------------------------------------------------
For a discussion of the change in fuel costs, see Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations.
SPPC's long-term contract with Black Butte Coal Company for coal shipments
to Valmy from the mine near Rock Springs, Wyoming, remains in effect until June
30, 2007, or until all volume requirements under the contract are delivered
and/or cancelled. Due to previous accelerated purchases and cancellations, and
continuing cancellations of minimum monthly volume obligations, SPPC fully
satisfied all volume requirements and termination of the contract occurred in
February 2002.
SPPC's long-term coal contract with Canyon Fuel Company, LLC (Canyon),
which provides coal for Valmy from Canyon's SUFCO mine in Central Utah, expires
on June 30, 2003. This contract also contains minimum volume requirements that
SPPC expects to meet each year until termination. The current owner of the SUFCO
mine is Arch Coal, Inc., which acquired ARCO Coal (the previous owner of the
Canyon properties, including SUFCO) on June 1, 1998.
During 2001, two short-term agreements for the purchase of spot market coal
were in place. The source of this coal is the Uinta Basin of Utah. These spot
market purchases supplement base volume requirements under SPPC's long-term coal
contracts at a cost approximately one-half that of contract coal.
As of December 31, 2001, Valmy's coal inventory level was 378,011 tons, or
approximately 65 days of consumption at 100% capacity. Inventory levels were
increased to allow for economically priced supplies under contract to be
delivered prior to the expiration of those supply arrangements.
During 2001, transportation of coal to Valmy was provided by the Union
Pacific Railroad (UP) under a 3-year agreement effective June 1, 1998. The
agreement was extended an additional 3.5 years and will now expire December 31,
2004.
During 2001, SPPC operated the Pinon Pine facility exclusively on natural
gas. No coal was purchased in 2001 for synthetic gas production in the plant's
coal gasification facility.
23
SPPC meets its needs for residual oil for generation through purchases on
the spot market. During portions of 2001, oil prices were significantly lower
than natural gas prices. Additional oil supply was ordered for consumption and
to ensure the ability of the electric division to make gas available to SPPC's
natural gas business on peak days. The actual residual oil inventory level at
these two sites was 318,000 barrels as of December 31, 2001, which is equal to a
14-day supply at full load operation.
Natural Gas Business
SPPC's natural gas business consists of operating the local distribution
company (LDC) for the Reno/Sparks metropolitan area and procuring gas for
electrical power generation at the Tracy and Ft. Churchill plants. The LDC
accounted for $145.7 million in 2001 operating revenues or 9.4% of SPPC's
revenues from continuing operations. Growth in SPPC's LDC service territory
continues to be strong. Customer meter count growth during 2001 was 4.7%. SPPC's
total customer meter count increased by 5,446 to 121,862 meters by the end of
2001.
Growth in all sectors is expected to continue as new developments in SPPC's
distribution service area are planned. SPPC's forecast for growth in the number
of LDC customers in 2002 is: residential 4.8%, small commercial 2.5%, and large
commercial 5.5%.
SPPC's natural gas LDC business is subject to competition from other
suppliers and other forms of energy available to its customers. Large customers
with fuel switching capability compare natural gas prices on an interruptible
basis to alternative energy source prices. Additionally, large customers have
the ability to secure their own gas supplies; however, through 2000 and 2001,
large customers that were securing their own supplies generally found that
receiving gas from SPPC's LDC was more reliable and more economical than
securing their own supplies. At the end of 2001, only two large customers were
still securing their own supplies.
To secure gas supplies for power generation and the LDC, SPPC contracted
for firm winter-only and annual gas supplies with 10 Canadian and domestic
suppliers to meet the firm requirements of its LDC and electric operations. The
winter period contracts totaled 160,000 Dth per day through March 2001, and the
summer period contracts totaled 115,000 Dth per day for April through October
2001.
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 and liquefied natural gas (LNG) storage from a
facility located near Lovelock, Nevada. The LNG facility is operated by Paiute
Pipeline Company and is used for meeting peak demand. The Jackson Prairie and
LNG facilities can contribute a total of approximately 48,000 Dth per day of
peaking supplies.
In November 1996, SPPC entered an agreement to sell winter seasonal peaking
capacity supplies to another company over a seven-year period. The contract
provides for the payment to SPPC of a monthly reservation charge, reimbursement
of pipeline capacity charges during the winter, and a volumetric commodity
charge based on the market price for natural gas. SPPC was able to enter into
this agreement due to the ability of its power plants to utilize alternative
fuels and its power importation option.
Following is a summary of the transportation and approximate storage
capacity of SPPC's current gas supply program for 2001 (for the twelve months
period ending October 31, 2002). Firm transportation capacity on the
Northwest/Paiute system exists to serve primarily the LDC. Firm transportation
capacity on the PGT/Tuscarora system exists primarily to serve SPPC's electric
generating plants. Storage capacity is generally used for the peaking
requirements of the LDC.
24
Transportation Capacity
- -----------------------
Northwest: 68,696 decatherms per day firm (annual)
90,000 decatherms per day interruptible
Paiute: 103,774 decatherms per day firm (November through March)
61,044 decatherms per day firm (April through October)
90,000 decatherms per day interruptible
NOVA: 103,774 decatherms per day firm
ANG: 93,301 decatherms per day firm
PGT: 83,500 decatherms per day firm (annual)
60,270 decatherms per day firm (November through April)
90,000 decatherms per day interruptible
Tuscarora: 121,911 decatherms per day firm (annual)
50,000 decatherms per day interruptible
Storage Capacity
- ----------------
Williams: 281,242 decatherms from Jackson Prairie
12,687 decatherms per day from Jackson Prairie
Paiute: 463,034 decatherms from Lovelock LNG
35,078 decatherms per day from Lovelock LNG facility
Total LDC Dth supply requirements in 2000 and 2001 were 13.2 million Dth
and 14.26 million Dth, respectively. Electric generating fuel requirements for
2001 and 2000 were 28.96 million Dth and 38.6 million Dth, respectively.
In January 2001, the PUCN approved a Purchase Gas Adjustment filing from
the previous year and the new rates became effective February 1, 2001. An
average residential customer had an increase in their rates of approximately
35%. In November 2001, the PUCN approved another Purchase Gas Adjustment filing.
An average residential customer had an increase in their rate of approximately
25%. Each of these approvals reflects complete recovery of the LDC's gas
purchases.
As of December 31, 2001, SPPC owned and operated 1,601 miles of three-inch
equivalent natural gas distribution piping, 108 miles of which were added in
2001. Also during 2001, Tuscarora Gas completed construction of a lateral gas
transmission line to a new SPPC high-pressure regulator station (completed in
2000). The lateral transmission line connected Tuscarora's primary transmission
line to SPPC's LDC north of Reno in the Stead, Nevada area. The line provided
the LDC the ability to receive more supply and exercise more operating
flexibility. In 2001, SPPC completed several smaller system improvement
projects. A small propane system that SPPC owns and operates was connected to
the new Tuscarora Gas lateral line and converted to a natural gas system. Over 4
miles of 12" diameter main was added to the system, which improved the capacity
and reliability in the southwest Reno area.
Sale of Water Business
On June 11, 2001, SPPC closed the sale of its water business to the Truckee
Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8 million
gain on the sale, net of income taxes of $18.2 million. Pursuant to a
stipulation entered into in connection with the sale and approved by the PUCN,
SPPC is required to refund to customers $21.5 million of the proceeds from the
sale. The refund is being credited on the electric bills of SPPC's former water
customers over a period not to exceed fifteen months from June 11, 2001.
Under a service contract with TMWA, SPPC will provide, on an interim basis,
customer service, billing, and meter reading services to TMWA. Transfer of the
hydroelectric facilities included in the contract of sale for an additional $8
million will require action by the CPUC. The sale agreement contemplates a
second
25
closing for the hydroelectric facilities to accommodate the CPUC's review of the
transaction. Not included in the sale were certain properties along the Truckee
River related to the hydroelectric facilities and in California at Independence
Lake. SPPC will continue to own this property with the intent of a possible
future sale.
Regulation and Rate Proceedings
See Regulation and Rate Proceedings in Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations.
GENERATION DIVESTITURE (NPC AND SPPC)
-------------------------------------
As a condition to its approval of the merger between SPR and NPC, the PUCN
required the Utilities to file a Divestiture Plan for the sale of their electric
generation assets. The PUCN approved a revised Divestiture Plan stipulation in
February 2000. In May 2000 an agreement was announced for the sale of NPC's 14%
undivided interest in the Mohave Generating Station ("Mohave"). In the fourth
quarter of 2000 the Utilities announced agreements to sell six additional
bundles of generation assets described in the approved Divestiture Plan. The
sales were subject to approval and review by various regulatory agencies.
AB 369, which was signed into law on April 18, 2001, prohibits until July
2003 the sale of generation assets and directs the PUCN to vacate any of its
orders that had previously approved generation divestiture transactions. In
January 2001, California enacted a law that prohibits until 2006 any further
divestiture of generation properties by California utilities, including SPPC,
and could also affect any sale of NPC's interest in Mohave after July 2003 since
the majority owner of that project is Southern California Edison. In addition,
SPPC's request for an exemption from the requirements of a separate California
law requiring approval of the CPUC to divest its plants was denied, subject to
future refiling.
The sales agreements for the six bundles provide that they terminate
eighteen months after their execution unless the parties agree to an earlier
termination. The parties may extend the termination another six months to obtain
additional regulatory approvals. As a result of the legislative and regulatory
developments which have rendered the contracts impossible to perform, the
Utilities are engaged in discussions with the buyers of the generation assets
regarding the formal termination of the sales agreements and the related energy
buyback contracts and interconnection agreements. As of December 31, 2001, the
Utilities had incurred costs of approximately $12.3 million and $15.5 million,
respectively, in order to prepare for the sale of generation assets. The
Utilities have requested recovery of these costs in each Utility's respective
general rate case filing with the PUCN, discussed in Regulation and Rate
Proceedings, in Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operation.
PORTLAND GENERAL ELECTRIC ACQUISITION
-------------------------------------
On April 26, 2001, SPR and Enron Corp. announced that they had mutually
agreed to terminate their agreement for SPR's purchase of Enron's wholly owned
subsidiary, Portland General Electric (PGE). In negotiating the mutual
termination, SPR agreed to share certain expenses that Enron Corp and PGE had
incurred for the proposed transaction. The Consolidated Statement of Income of
SPR for the year ended December 31, 2001, reflects a charge in connection with
the planned purchase of PGE of $22 million, including approximately $7.5 million
representing a termination payment for shared expenses.
ENVIRONMENT (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
26
or transmission facilities. The United States Environmental Protection Agency
(EPA), Nevada Division of Environmental Protection (NDEP), and Clark County
Health District (CCHD) 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.
Nevada Power Company
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.
The plant owners and plaintiffs have had numerous settlement discussions and
filed a proposed settlement with the court in October 1999. The consent decree,
approved by the court in November 1999, established emission limits for sulfur
dioxide and opacity and required installation of air pollution controls for
sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits
must be met by January 1, 2006 and April 1, 2006 for the first and second units
respectively. However, if the owners sell their entire ownership interest with a
closing date prior to December 30, 2002, the new emission limits become
effective 36 months and 39 months from the date of last closing for the two
respective units. The estimated cost of new controls is $395 million. As a 14%
owner in the Mohave Station, NPC's cost could be $55 million.
Also, the United States Congress authorized the EPA to study the potential
impact Mohave may have on visibility in the Grand Canyon area. A final report of
the study results was released in March 1999. The study acknowledges that sulfur
dioxide emissions from Mohave are transported to the Grand Canyon. The EPA has
solicited information to determine whether visibility impairment in the Grand
Canyon can be reasonably attributed to Mohave. The EPA determined that
significant visibility impairment to the Grand Canyon cannot be reasonably
attributable to the station provided controls are installed as agreed to in the
consent order. Therefore, the EPA will not require a Best Available Retrofit
Technology Review. Provisions that were agreed to in the settlement will be
reflected in the state Implementation Plan for Nevada.
In May 1997, NDEP ordered NPC to submit a plan to eliminate the discharge
of Reid Gardner Station wastewater to groundwater. The NDEP order also required
a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP
determined that wastewater ponds had degraded groundwater quality. In August
1999, 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 next 10 years. This order also required NPC to submit a Site
Characterization Plan to NDEP to ascertain impacts. This plan is under review by
NDEP. After approval, an estimate of remediation costs will be determined by
NPC. New pond construction and lining costs are estimated at $15 million.
Also, at the Reid Gardner Station, the NDEP has determined that there is
additional groundwater contamination that resulted from oil spills at the
facility. NDEP has required submitting a corrective action plan. The extent of
contamination has been determined and remediation is occurring at a modest rate.
An engineering evaluation of the current remediation technology will occur in
2002 to verify efficiency and to expedite remediation. Remediation modifications
are not expected to materially affect the financial position of SPR or NPC.
In May 1999, NDEP issued an order to eliminate the discharge of NPC's Clark
Station wastewater to groundwater. The order also required a hydrological
assessment of groundwater impacts in the area. This assessment, submitted to
NDEP in February 2001, warranted a Corrective Action Plan which was submitted to
NDEP in November and is pending review. Remediation costs are expected to be in
the $500,000 - $750,000
27
range. In addition to remediation, NPC will spend $789,000 to line existing
ponds. After review and approval of the Corrective Action Plan by NDEP, NPC will
implement remediation.
In July 2000, NPC received a request from the EPA for information to
determine the compliance of certain generation facilities at the Clark Station
with the applicable State Implementation Plan. In November 2000, NPC and the
Clark County Health District 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. If the EPA prevails, capital expenditures
and temporary outages of four of Clark Station's generation units could be
required. Additionally, depending on the time of year that the compliance
activity and corresponding generation outage would occur, the incremental cost
to purchase replacement energy could be substantial.
Sierra Pacific Power Company
In September 1994, Region VII of EPA notified SPPC that it was being named
as a potentially responsible party (PRP) regarding the past improper handling of
Polychlorinated Biphenyls (PCBs) by PCB Treatment, Inc., located in Kansas City,
Kansas, and Kansas City, Missouri (the Sites). The EPA is requesting that SPPC
voluntarily pay an undefined, pro rata share of the ultimate clean-up costs at
the Sites. A number of the largest PRP's formed a steering committee, which is
chaired by SPPC. The responsibility of the Committee is to direct clean-up
activities, determine appropriate cost allocation, and pursue actions against
recalcitrant parties, if necessary. The EPA issued an administrative order on
consent requiring signatories to perform certain investigative work at the
Sites. The steering committee retained a consultant to prepare an analysis
regarding the Sites. The Site evaluations have been completed. EPA is developing
an allocation formula to allocate the remediation costs. SPPC has recorded a
preliminary liability for the Sites of $650,000 of which approximately $136,000
has been spent through December 31, 2001. Once evaluations are completed, SPPC
will be in a better position to estimate and record the ultimate liabilities for
the Sites.
Other Subsidiaries of SPR
LOS, a wholly owned subsidiary of SPR, owns property in North Lake Tahoe,
California, which is leased to independent condominium owners. The property has
both soil and groundwater petroleum contaminate resulting from an underground
fuel tank that has been removed from the property. Additional contaminate from a
third party fuel tank on the property has also been identified and is undergoing
remediation. Estimated future remediation costs are not expected to be
significant.
NEICO, a wholly owned subsidiary of SPR, owns property in Wellington, Utah,
which was the site of a coal washing and load out facility. The site now has a
reclamation estimate supported by a bond of $4 million with the Utah Division of
Oil and Gas Mining. The property was under contract for sale and the contract
required the purchaser to provide $1.3 million in escrow towards reclamation.
However, the sales contract was terminated and NEICO took title to the escrow
funds. In September 2000, NEICO leased the property together with an option to
purchase. It is NEICO's intention to either lease or sell the property.
OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES
----------------------------------------------
Tuscarora Gas Pipeline Company
TGPC was formed as a wholly owned subsidiary in 1993 for the purpose of
entering into a partnership (Tuscarora Gas Transmission Company or TGTC) with a
subsidiary of TransCanada to develop, construct and operate a natural gas
pipeline to serve an expanding gas market in Reno, northern Nevada, and
northeastern California. In December 1995, TGTC completed construction and began
service on its 229-mile pipeline
28
extending from Malin, Oregon to Reno, Nevada. TGTC interconnects with PG&E Gas
Transmission - Northwest (GT-NW) at Malin, Oregon. GT-NW is a major interstate
natural gas pipeline extending from the U.S./Canadian border, at a point near
Bonners Ferry, Idaho to the Oregon/California border. The GT-NW system provides
TGTC customers access to natural gas reserves in the Western Canadian
Sedimentary basin, one of the largest natural gas reserve basins in North
America. As of December 31, 2001, SPR had an investment of approximately $14.6
million in this subsidiary.
As an interstate pipeline, TGTC provides only transportation service. SPPC
was the largest customer of TGTC during 2001, contributing 80% of revenues.
Malin, Oregon began taking service from TGTC during October 1996. The Sierra
Army Depot at Herlong, California began taking service from TGTC in October
1997. In 1998, TGTC began serving two new customers, the United States Gypsum
Company located north of Empire, Nevada, and HL Power Company located northwest
of Wendel, California.
In 2000, TGTC began construction on a 14.2-mile lateral, creating a new
city gate connection into the SPPC distribution system. The lateral was
completed and placed in service January 29, 2001, providing SPPC with an
additional 10,000 Dth per day of firm transportation capacity in January 2001
and 5,661 Dth in November 2001. Also in 2000, TGTC surveyed shipper interest in
the feasibility of an expansion of transportation capacity. This survey
established that 95,912 Dth per day of new capacity would be required to meet
the needs of existing and new shippers for the 2002-2003 winter heating season.
Facilities required in Nevada would be approximately 14.2 miles of 20" diameter
pipe and one 600 HP booster unit, and in California, three compressor stations
each with a 6,000 HP turbine and related facilities. On January 30, 2002, the
FERC approved the plans to expand the interstate gas pipeline owned by the
Tuscarora Gas Transmission Company. The project will increase the pipeline's
capacity by 74% and will improve reliability of the natural gas transmission
systems that serve northern Nevada. Final permitting for the project is pending
before the U.S. Bureau of Land Management and other state and local agencies.
In May 2001, TGTC completed construction of approximately 3,520-feet of
pipeline with meter and flow control to serve a 360 MW plant, a new
interruptible transportation customer east of Reno, Nevada near SPPC's Tracy
Power Plant, and in September, 2001, TGTC completed construction of a 10.8-mile
pipeline to serve two new customers: the City of Susanville and the Department
of Correction both in California.
For a discussion of TGPC's results of operations, refer to Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
Sierra Pacific Communications
SPC was created to examine and pursue telecommunications opportunities that
leverage SPPC's existing skills of installing and deploying pipe and wire
infrastructure. SPC presently has fiber optic assets deployed in the cities of
Reno and Las Vegas.
SPC is currently marketing bandwidth services in the Reno/Sparks and Las
Vegas metropolitan areas.
Sierra Touch America LLC (STA), a partnership between SPC and Touch
America, a subsidiary of Montana Power Company, is constructing a fiber optic
line between Salt Lake City, Utah and Sacramento, CA. The conduits included in
the line are under contract to be sold to AT&T, PF Net corporations, and STA.
SPC is responsible for 50% of the partnership's operating expenses and shares in
the construction cost of the fiber network. Construction activity between
Sacramento and Reno commenced in July 2000. Construction within Salt Lake City
is complete and construction is in progress through the Reno, NV metropolitan
area. The entire project is expected to be completed by mid 2003.
For a discussion of the legal proceedings affecting SPC refer to Item 3,
Legal Proceedings.
29
For a discussion of SPC's results of operations refer to Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
e.three
e.three was organized in October 1996 as an unregulated wholly owned
subsidiary of SPR. It provides comprehensive energy and other business solutions
in commercial and industrial markets. This is accomplished by offering a variety
of energy-related products and services to increase customers' productivity and
profits and improve the quality of the indoor environment. These products and
services include: technology and efficiency improvements to lighting, heating,
ventilation and air-conditioning equipment; installation or retrofit of controls
and power quality systems; energy performance contracting; end-use services; and
ongoing energy monitoring and verification services.
In September 1998, e.three and NEICO, then a wholly owned subsidiary of
NPC, formed e.three Custom Energy Solutions, LLC, a Nevada limited liability
company, for the purpose of selling and implementing energy-related performance
contracts and similar energy services in southern Nevada. e.three Custom Energy
Solutions, LLC's primary focus for its sales activities is in the commercial and
industrial markets.
In October 1998, e.three acquired Independent Energy Consulting, Inc.
(IEC), a California based company, in an exchange of SPR stock for all of IEC's
stock. IEC provides energy procurement management, third party auditing,
performance contract consulting and strategic energy planning in the industrial
and commercial markets.
In mid 2000, e.three Custom Energy Solutions, LLC completed the
construction of a chilled water cooling plant in the downtown area of Las Vegas.
The plant is owned by e.three Custom Energy Solutions, LLC and supplies the
indoor air-cooling requirements for a number of businesses in its immediate
vicinity.
For a discussion of e.three's results of operations refer to Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
Sierra Pacific Energy Company
SPE was formed to market a package of technology and energy-related
products and services in Nevada. SPE filed an application with the PUCN to be
licensed as an Alternative Seller of Electricity in the state of Nevada. SPE has
withdrawn its application with the PUCN and dissolved its retail energy
marketing efforts. SPE continues to manage several long term commitments entered
into prior to its withdrawal from the retail energy marketing effort.
For a discussion of SPE's results of operations refer to Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
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.
Remaining properties include land in Nevada and California. SPR has decided to
focus on its core energy business. In keeping with this strategy, LOS continues
to sell its remaining properties.
For a discussion of LOS' results of operations refer to Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
30
Nevada Electric Investment Company
NEICO is a wholly owned subsidiary of SPR. In October of 1997, NEICO and
UTT Nevada, Inc., an affiliate of Exelon Thermal Technologies, formed Northwind
Las Vegas, LLC, a Nevada limited liability company, for the purpose of
evaluating district energy projects in southern Nevada. Also, in October of
1997, NEICO and UTT Nevada, Inc. formed Northwind Aladdin, LLC, a Nevada limited
liability company, for the purpose of owning, constructing, operating and
maintaining the facility for the production and distribution of chilled water,
hot water and emergency power for the Aladdin Hotel and Casino project in Las
Vegas, Nevada. The project was completed in the first quarter of 2000 and is
operational.
In September 1998, NEICO and e.three formed e.three Custom Energy
Solutions, LLC, a Nevada limited liability company, for the purpose of selling
and implementing energy-related performance contracts and similar energy
services in southern Nevada. Refer to e.three for a more complete discussion of
these activities
For a discussion of NEICO's results of operations refer to Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
GENERAL - EMPLOYEES (ALL)
-------------------------
SPR and its subsidiaries had 3,333 employees as of December 31, 2001, of
which 1,787 were employed by NPC and 1,415 were employed by SPPC.
NPC's current contract with the International Brotherhood of Electrical
Workers (IBEW) Local No. 396, which covers 55% of NPC's workforce, was
renegotiated in February 2002 and is in effect until February 1, 2005. The
contract provides for a 3% general wage increase for bargaining unit employees
effective February 2, 2002, with 3% increases in 2003 and 2004.
SPPC's current contract with the IBEW Local No. 1245, which represents 62%
of SPPC's workforce, was renegotiated in March 2000 and is in effect until
December 31, 2002. The two-year contract provided for 3% general wage increases
for bargaining unit employees beginning January 1, 2001, and January 1, 2002. In
addition, the contract provides for participation by bargaining unit employees
in the incentive compensation program.
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. During 2001, the state also passed
a law requiring public utilities to collect from their customers a fee based on
consumption. This universal energy charge is to help those customers who need
assistance in paying their utility bills or need help in paying for ways to
reduce energy consumption. During 2001, the Utilities collected $58.3 million in
franchise or other fees based on gross revenues. They collected $3.9 million in
universal energy charges based on consumption. They also paid and recorded as
expense $0.5 million of fees based on net profits.
31
Franchise Type of Service Expiration Date
--------------------------------------------------------------------------------
NPC:
Las Vegas Electric November 2029
Clark County Electric May 2004
Nye County Electric May 2006
City of Henderson * Electric November 1999
SPPC:
Reno Electric, Gas and Water** January 2006
Sparks Electric May 2006
Sparks Gas May 2007
Sparks Water** April 2004
Carson City Electric February 2012
City of Elko Electric April 2017
City of South Lake Tahoe Electric April 2018
Washoe County Gas and Water** May 2015
Washoe County Electric September 2015
Eureka County Electric July 2018
*currently being renegotiated.
** Water rights and obligations under the franchise agreements were assumed
by Truckee Meadows Water Authority in June 2001 upon the sale of SPPC's water
business.
The Utilities will apply for renewal of franchises in a timely manner prior
to their respective expiration dates.
GENERAL - RESEARCH AND DEVELOPMENT (ALL)
----------------------------------------
SPR, through its NPC and SPPC subsidiaries, participates in several utility
associations, including the Electric Power Research Institute.
SPR has invested in Nth Power Technologies (Nth), a venture capital fund
that invests in developing technology companies. Nth has made several
investments that may result in SPR strengthening its market position and
developing new products and services.
ITEM 2. PROPERTIES
The general character of SPR's, NPC's, and SPPC's principal facilities is
discussed in Item 1 - Business.
Substantially all of NPC's utility plant is subject to the lien of the
Indenture of Mortgage, dated October 1, 1953, and supplemental indentures
thereto among NPC and Bankers Trust Company, securing NPC's outstanding first
mortgage bonds.
Additionally, 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, which lien is junior, subject and subordinate
to the prior lien of the Indenture of Mortgage mentioned above.
Substantially all of SPPC's utility plant is subject to the lien of the
Indenture of Mortgage, dated December 1, 1940, and supplemental indentures
thereto between SPPC and State Street Bank and Trust, and Gerald R. Wheeler, as
trustees, securing SPPC's outstanding first mortgage bonds.
32
Additionally, all of SPPC's property in 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, which lien is junior, subject and
subordinate to the prior lien of the Indenture of Mortgage mentioned above.
Item 3. Legal Proceedings
Sierra Touch America LLC (STA), a partnership between SPC and Touch
America, a subsidiary of Montana Power Company, is constructing a fiber optic
line between Salt Lake City, Utah and Sacramento, CA. The conduits included in
the line are under contract to be sold to AT&T, PF Net corporations, and STA.
SPC is responsible for 50% of the partnership's operating expenses and shares in
the construction cost of the fiber network. Construction activity between
Sacramento and Reno commenced in July 2000, and the estimated completion date
has been moved to early 2003. Williams Communications, LLC ("Williams") has
filed a complaint in United States District Court alleging that STA has failed
to make timely payment on invoices in connection with a construction agreement
between Williams and STA. TI Energy Services ("TI") has filed a complaint in the
District Court of Harris County, Texas, alleging that STA has failed to make
timely payment on invoices in connection with a services agreement between TI
and STA, whereby TI is to provide services for certain segments of the fiber
optic line. Although SPC's ultimate liability, if any, cannot be estimated,
Management believes the final outcome of the litigation is not likely to have a
material adverse effect on SPR's financial position or results of operations.
SPPC owns a 345 kV transmission line that connects SPPC to the facilities
of the Bonneville Power Administration ("BPA") near Alturas, California. The
Transmission Agency of Northern California ("TANC") initiated proceedings in the
United States District Court for the Eastern District of California and the
United States Court of Appeals for the Ninth Circuit, in each case alleging that
BPA's construction of a small portion of the Alturas Intertie violated the
Northwest Power Preference Act and requesting an injunction prohibiting
operation of the Alturas Intertie. The case before the Eastern District was
dismissed for lack of jurisdiction. The case before the Ninth Circuit was
dismissed for TANC's failure to prosecute. In December 1999, TANC filed suit in
the Superior Court of the State of California, Sacramento County, seeking an
injunction against operation of the Alturas Intertie based on numerous
allegations under state law, including inverse condemnation, trespass, private
nuisance, and conversion. That case was removed to Federal Court and dismissed
by the trial court, and is now on appeal in the Ninth Circuit. Although SPPC's
ultimate liability, if any, cannot be estimated at this time, Management
believes the final outcome of the appeal and any subsequent litigation is not
likely to have a material adverse effect on SPR's financial position or results
of operation.
See Environment in Item 1, Business, for information on environmental
proceedings.
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 has had or, in the opinion of management, is expected to have a
significant impact on their financial positions or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
33
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
SIERRA PACIFIC RESOURCES
------------------------
SPR's Common Stock is traded on the New York Stock Exchange (symbol
SRP). The dividends paid per share and high and low sale prices of the Common
Stock in the consolidated transaction reporting system in "The Dow Jones News
Retrieval Service" for 2001 and 2000 are as follows:
Dividends
Paid
Per Share High Low
--------------- ---------- ------------
2001 First Quarter $.250 $ 16.000 $ 10.800
Second Quarter .000 17.000 13.290
Third Quarter * .200 17.020 14.670
Fourth Quarter * .200 15.560 13.850
2000 First Quarter .250 18.437 12.125
Second Quarter .250 15.687 12.500
Third Quarter .250 19.437 12.562
Fourth Quarter .250 18.062 14.875
* For federal income tax purposes, these payments were
determined to be return of capital and therefore not taxable
as ordinary income.
Number of Security Holders:
Title of Class Number of Holders
-------------- -----------------
Common Stock: $1.00 Par Value As of March 15, 2002: 25,019
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 condition and other matters within the
discretion of the Board. As a result of the unprecedented conditions in the
wholesale energy markets that negatively affected SPR's earnings prior to the
restoration of deferred energy accounting in Nevada, the Board of Directors
decided on April 13, 2001 not to pay the Common Stock dividend that, if it had
followed historical practices, would have been paid in May 2001. Following the
passage of legislation in Nevada which reinstated deferred energy accounting for
electric utilities, the Board re-examined the factors described previously and
on July 20, 2001 declared a dividend of $.20 per share on SPR's Common Stock,
payable September 15, 2001. The Board of Directors also established the
following schedule for when future dividends would normally be paid, if
declared: December 15, March 15, June 15 and September 15. The Board
subsequently voted on November 6, 2001 to declare a dividend of $.20 per share,
payable December 15, 2001. The Board will continue to review these factors 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.
34
On February 6, 2002, the SPR Board of Directors declared a quarterly common
dividend of $.20 per share. This dividend of approximately $20.4 million will be
paid on March 15, 2002, to holders of record as of February 22, 2002.
The primary source of funds for the payment of dividends to SPR's
stockholders is dividends paid to SPR by NPC and SPPC on their common stock, all
of which is owned by SPR. These two subsidiaries are public utilities and are
subject to regulation by state utility commissions which may impose limits on
investment returns or otherwise impact the amount of dividends which may be paid
by those companies. Moreover, the Articles of Incorporation of SPPC contain
restrictions on the payment of dividends on SPPC's common stock in the event of
a default in the payment of dividends on SPPC's preferred stock. Similarly, the
bank credit facilities of NPC and SPPC prohibit the payment of dividends on each
company's common stock if that company is in default under the terms of the
relevant credit facility. Finally, the terms of certain outstanding series of
first mortgage bonds of both NPC and SPPC contain certain quantitative limits on
the amount of dividends that may be paid on each company's common stock.
35
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
------------------------
The table below, for periods prior to July 28, 1999, reflects historical
information for NPC.
Year ended December 31,
(dollars in thousands, except per share amounts)
------------------------------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Operating Revenues $ 4,588,730 $ 2,334,254 $ 1,284,792 $ 873,682 $ 799,148
============ ============== ============= =============== =============
Operating Income $ 222,869 $ 127,389 $ 162,861 $ 147,277 $ 137,196
============ ============== ============= =============== =============
Net Income (Loss)
from Continuing Operations $ 29,866 $ (49,414) $ 48,210 $ 83,499 $ 82,091
============= ============== ============= =============== =============
Income (Loss) from Continuing Operations
Per Average Common Share - Basic $ 0.34 $ (0.63) $ 0.77 $ 1.64 $ 1.65
============= ============== ============= =============== =============
Income (Loss) from Continuing Operations
Per Average Common Share - Diluted $ 0.34 $ (0.63) $ 0.77 $ 1.64 $ 1.65
============= ============== ============= =============== =============
Total Assets $ 8,181,314 $ 5,677,908 $ 5,235,917 $ 2,541,840 $ 2,339,422
============= ============== ============= =============== =============
Long-Term Debt and
SPPC/NPC Obligated Mandatorily
Redeemable Preferred Trust Securities $ 3,564,977 $ 2,371,051 $ 1,793,999 $ 1,089,099 $ 1,014,311
============= ============== ============= =============== =============
Dividends Declared Per
Common Share $ 0.40 $ 1.00 $ 1.17 $ 1.45 $ 1.60
============= ============== ============= =============== =============
36
NEVADA POWER COMPANY
--------------------
Year ended December 31,
(dollars in thousands)
----------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Operating Revenues $ 3,025,103 $ 1,325,470 $ 977,262 $ 873,682 $ 799,148
=============== =============== ================ ================ ==================
Operating Income $ 144,364 $ 73,460 $ 116,983 $ 147,277 $ 137,196
=============== =============== ================ ================ ===================
Net Income (Loss) $ 56,733 $ (39,780) $ 51,750 $ 83,499 $ 82,091
=============== =============== ================ ================ ==================
Total Assets $ 5,225,369 $ 3,407,751 $ 3,378,485 $ 2,541,840 $ 2,339,422
=============== =============== ================ ================ ==================
Long-Term Debt and
Obligated Mandatorily
Redeemable Preferred Trust Securities $ 1,796,839 $ 1,116,656 $ 1,119,876 $ 1,089,099 $ 1,014,311
=============== =============== ================ ================ ==================
Dividends Declared - Common Stock $ 33,000 $ 64,000 $ 72,000 $ 73,715 $ 79,177
=============== =============== ================ ================ ==================
SIERRA PACIFIC POWER COMPANY
----------------------------
The table below, for the years ended December 31, 1998 and 1997,
includes information for SPPC's water business disposed of in 2001.
Year ended December 31,
(dollars in thousands)
----------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Operating Revenues $ 1,544,786 $ 994,585 $ 709,374 $ 685,189 $ 657,540
=============== =============== ================ ================ ==================
Operating Income $ 78,968 $ 47,135 $ 112,703 $ 114,263 $ 120,172
=============== =============== ================ ================ ==================
Net Income (Loss)
from Continuing Operations $ 19,043 $ (7,576) $ 59,658 $ 79,678 $ 77,668
=============== =============== ================ ================ ==================
Total Assets $ 2,685,907 $ 2,208,389 $ 2,084,707 $ 2,011,820 $ 1,912,242
=============== =============== ================ ================ ==================
Long-Term Debt and
Obligated Mandatorily
Redeemable Preferred Trust Securities $ 923,070 $ 654,316 $ 673,930 $ 654,950 $ 655,389
=============== =============== ================ ================ ==================
Dividends Declared - Common Stock $ 63,000 $ 85,000 $ 76,000 $ 76,000 $ 72,000
=============== =============== ================ ================ ==================
37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 rulings in rate cases previously filed and to be filed
by NPC and SPPC (the "Utilities") with the Public Utilities
Commission of Nevada (PUCN), including the periodic applications
authorized by recent Nevada legislation to permit the Utilities to
recover costs for fuel and purchased power that have been recorded
by the Utilities in their deferred energy accounts and deferred
natural gas recorded by SPPC for its gas distribution business;
(2) the ability of SPR, NPC and SPPC to access the capital markets to
support their requirements for working capital, including amounts
necessary to finance deferred energy costs, construction costs and
the repayment of maturing debt, particularly in the event of
unfavorable rulings by the PUCN and/or a downgrade of the existing
debt ratings of SPR, NPC or SPPC;
(3) whether the PUCN will issue favorable orders in a timely manner to
permit the Utilities to borrow money and issue additional securities
to finance the Utilities' operations and to purchase power and fuel
necessary to serve their respective customers;
(4) the extent to which volatile energy prices and the financial
difficulties of electric utilities and power exchanges in the
western United States cause any counterparties to the Utilities'
purchased power contracts to default on their obligations, thus
requiring the Utilities to seek to replace the power on the spot
market;
(5) the effect of price controls promulgated in June 2001 by the Federal
Energy Regulatory Commission ("FERC") on the price at which the
Utilities can sell excess power in the wholesale markets;
(6) the effect that any future terrorist attacks may have on the tourism
and gaming industries in Nevada, particularly in Las Vegas, as well
as on the economy in general;
(7) the effect of existing or future Nevada, California or federal
legislation or regulations affecting electric industry
restructuring, including laws or regulations which could allow
certain customers to choose new electricity suppliers;
(8) unseasonable weather and other natural phenomena, which can have
potentially serious impacts 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;
38
(9) industrial, commercial and residential growth in the service
territories of the Utilities;
(10) the loss of any significant customers;
(11) changes in the business of major customers, including those engaged
in gold mining or gaming, which may result in changes in the demand
for services of the Utilities;
(12) changes in environmental regulations, tax or accounting matters or
other laws and regulations to which the Utilities are subject;
(13) future economic conditions, including inflation rates and monetary
policy;
(14) financial market conditions, including changes in availability of
capital or interest rate fluctuations;
(15) unusual or unanticipated changes in normal business operations,
including unusual maintenance or repairs; and
(16) employee workforce factors, including changes in collective
bargaining unit agreements, strikes or work stoppages.
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.
CRITICAL ACCOUNTING POLICIES
The following items represent critical accounting policies that under
different conditions or using different assumptions could have a material effect
on the financial condition, liquidity and capital resources of SPR and the
Utilities.
Regulatory Accounting
The Utilities' rates are currently subject to the approval of the PUCN
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.
39
Deferred Energy Accounting
On April 18, 2001, the Governor of Nevada signed into law Assembly Bill
(AB) 369. The provisions of AB 369, which are described in greater detail in
"Regulation and Rate Proceedings," later, 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 began utilizing deferred energy accounting on March 1, 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 income statement 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. AB 369 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, AB 369 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 to recover, a carrying charge on such deferred balances.
If not for deferred energy accounting during 2001, SPR's, NPC's and
SPPC's results of operations, financial condition, liquidity and capital
resources would have been materially adversely affected. For example, without
the deferred energy accounting provisions of AB 369, the 2001 reported net
income of SPR, NPC and SPPC of $56.7 million, $63.4 million/1/ and $45.9 million
would have been (net of income tax) reported as net losses of ($715.4) million,
($573.6) million/1/ and ($89.1) million, respectively. In addition, a
significant disallowance by the PUCN of costs currently deferred would have a
material adverse affect on the future results of operations of SPR, NPC and
SPPC. See "Regulation and Rate Proceedings," later, for a more detailed
discussion of deferred energy accounting, including the regulatory process
underway to recover these deferred costs.
Derivatives and Hedging Activities
Effective January 1, 2001, SPR, SPPC, and NPC adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended by
SFAS No. 138. As amended, SFAS No. 133 requires that an entity recognize all
derivative instruments as either assets or liabilities in the statement of
financial position and measure the instruments at fair value.
In order to manage loads, resources and energy price risk, the
Utilities buy fuel and power under forward contracts. In addition to forward
fuel and power purchase contracts, the Utilities also use options and swaps to
manage price risk. All of these instruments are considered to be derivatives
under 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 these forward fuel and power purchase contracts and other energy
related derivative instruments.
With the reinstatement of deferred energy accounting pursuant to AB
369, prudently incurred fuel and purchased power costs are expected to be
recoverable through future rates. Accordingly, the energy related risk
management assets and liabilities and the corresponding unrealized gains and
losses (changes in fair value) are offset with a regulatory asset or liability
rather than recognized in the statements of income and comprehensive income.
Upon settlement of the derivative instrument, actual fuel and purchased power
costs are recognized or deferred to the extent they are recoverable or payable
through future rates.
- -------------------------
/1/ Excludes equity in losses of SPR.
40
The fair values of the forward contracts and swaps are determined based
on quotes obtained from independent brokers and exchanges. The fair values of
options are determined using a pricing model which 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.
SPR and the Utilities have other non-energy related derivative
instruments such as interest rate swaps. The transition adjustment resulting
from the adoption of SFAS No. 133 related to these types of derivative
instruments was reported as the cumulative effect of a change in accounting
principle in Other Comprehensive Income. Additionally, the changes in fair
values of these non-energy related derivatives are also reported in the
statements of comprehensive income until the related transactions are settled or
terminate, at which time the amounts will be reclassified into earnings. No
amounts were reclassified into earnings during 2001.
See Note 22 of "Notes to Financial Statements" for additional
information regarding derivatives and hedging activities.
Provision for Uncollectible Accounts
The Utilities reserve for doubtful accounts based on past experience
writing off uncollectible customer accounts. The collapse of the energy markets
in California, and the subsequent bankruptcy of the California Power Exchange
and the financial difficulties of the Independent System Operator, resulted in
the Utilities reserving for outstanding receivables for power purchases by these
two entities of $19.9 million and $1.5 million (before taxes) for NPC and SPPC,
respectively. The weakening economy and the disruption to the leisure travel
industry after September 11th also impacted the Utilities' customer
delinquencies in 2001. Additional amounts of $14.8 million and $6.1 million were
reserved for delinquent retail customer accounts of NPC and SPPC, respectively.
The adequacy of these reserves will vary to the extent that future collections
differ from past experience. Uncollectible retail customer accounts amounting to
$5.6 million and $2.5 million respectively, for NPC and SPPC, were written off
against this provision in 2001. Significant collection efforts are underway to
recover portions of the rest of the delinquent accounts.
MAJOR FACTORS AFFECTING RESULTS OF OPERATIONS
As discussed in the results of operations sections that follow,
operating results for 2001 were affected by the high and extremely volatile fuel
and purchased power costs that developed in the western United States in 2000
and continued into 2001, and by several responsive legislative and regulatory
actions.
In an effort to mitigate the effects of higher fuel and purchased power
costs, in July 2000, the Utilities entered into the Global Settlement with the
PUCN, which established a mechanism that initiated incremental rate increases
for each Utility. Cumulative electric rate increases under the Global Settlement
were $127 million and $65 million per year, respectively, for the Utilities.
However, because the rate adjustment mechanism of the Global Settlement
was subject to certain caps and could not keep pace with the continued
escalation of fuel and purchased power prices, on January 29, 2001, the
Utilities filed a Comprehensive Energy Plan (CEP) with the PUCN. The CEP
included a request for emergency rate increases (CEP Riders). On March 1, 2001,
the PUCN permitted the requested CEP Riders to go into effect subject to later
review. The CEP Riders provided further rate increases of $210 million and $104
million per year, respectively, for NPC and SPPC.
41
Notwithstanding the increases under the Global Settlement and the CEP
Riders, the Utilities' revenues for fuel and purchased power recovery continued
to be less than the related expenses. Accordingly, the Utilities sought
additional relief pursuant to legislation.
On April 18, 2001, the Governor of Nevada signed into law AB 369. The
provisions of AB 369, which are described later in greater detail in "Regulation
and Rate Proceedings," include a moratorium on the sale of generation assets by
electric utilities until 2003, the repeal of electric industry restructuring,
and, beginning March 1, 2001, a reinstatement of deferred energy accounting for
fuel and purchased power costs incurred by electric utilities. The stated
purposes of this emergency legislation included, among others, to control
volatility in the price of electricity in the retail market in Nevada and to
ensure that the Utilities have the necessary financial resources to provide
adequate and reliable electric service under present market conditions.
As discussed above in "Critical Accounting Policies," deferred energy
accounting allows the Utilities an opportunity to recover in future periods that
portion of their costs for fuel and purchased power not covered by current rates
and defers to future periods the expense associated with the amounts by which
fuel and purchased power costs exceed the costs to be recovered in current
rates. Recovery is subject to PUCN review as to prudency and other matters.
AB 369 requires each Utility to file general rate applications and
deferred energy applications with the PUCN by specific dates. NPC's deferred
energy application, filed on November 30, 2001, seeks to establish a Deferred
Energy Accounting Adjustment ("DEAA") rate to clear accumulated purchased fuel
and power costs of $922 million and spread the cost recovery over a not more
than three-year period resulting in a net increase of 21%. The decision of the
PUCN on NPC's deferred energy application is to take effect on April 1, 2002.
SPPC's deferred energy application, filed on February 1, 2002, seeks to
establish a DEAA rate to clear accumulated purchased fuel and power costs of
$205 million and spread the cost recovery over a not more than three-year period
resulting in a net increase of 9.8%. The PUCN decision on SPPC's deferred energy
application is to take effect on June 1, 2002. See "Regulation and Rate
Proceedings," later, for a discussion of the Utilities' general rate case
filings.
The decisions of the PUCN on the Utilities' deferred energy
applications are expected to have a significant effect on the results of
operations of SPR, NPC, and SPPC in 2002 and subsequent periods, and may have a
material effect on the financial condition, liquidity, and capital resources of
SPR, NPC, and SPPC. In particular, to the extent that the PUCN finds that any
amount included in either Utility's deferred account was imprudently incurred,
the PUCN will not permit that amount to be recovered through higher rates, and
an equivalent amount of the Utility's deferred energy costs asset will be
required to be written off. Such a write-off could cause a substantial loss to
be incurred by the Utility, could cause its securities to be downgraded by the
rating agencies and could make it significantly more difficult to finance the
operations of the Utility and to buy fuel and purchased power from third
parties. In the event that a significant amount of the Utilities' deferred
energy costs are disallowed by the PUCN, there can be no assurance that SPR,
NPC, or SPPC will be able to remain solvent.
As discussed in greater detail in "Regulation and Rate Proceedings," on
June 19, 2001, the FERC adopted a price mitigation plan applicable to spot
market wholesale power sales in California and throughout the western United
States during the period June 20, 2001 through September 30, 2002. The price
mitigation plan established a mechanism with which to determine the maximum
amount that may be charged for power sold during this period. Although the
Utilities are not able to predict at this time the long-term effect that the
FERC price mitigation plan and other market developments may have on their
results of operations, management believes that, under certain market
conditions, the FERC plan adversely affects the availability of spot market
power to the Utilities and reduces the price at which the Utilities can sell
power on the wholesale market. Another potential result from these price
mitigation measures could be the delay and/or cancellation of proposed power
plants throughout the western United States. If these results occur, the
long-term supply of energy could be reduced. Numerous parties, including NPC and
several northwest utilities, appealed the FERC order to the District of Columbia
Court of Appeals on the basis that the price caps are unfair to electric
customers who reside outside of California. The parties to the appeal await
action by the Court.
42
SIERRA PACIFIC RESOURCES
------------------------
Results of Operations
SPR earned $56.7 million for the year ended December 31, 2001, compared
to a net loss of ($39.8) million in 2000, and net income of $51.8 million in
1999. NPC and SPPC, SPR's principal subsidiaries, declared common stock
dividends to their parent, SPR, of $33 million and $63 million, respectively.
SPPC also declared $3.9 million in dividends to holders of its preferred stock.
Liquidity and Capital Resources (SPR Consolidated)
SPR's net cash flows during 2001 were comparable to 2000. An increase
in net cash flows used for operating activities was offset by a decrease in cash
used for investing activities and an increase in cash provided from financing
activities. The increase in cash used in operating activities resulted
substantially from the payment of higher energy and natural gas costs. The
decrease in cash used for investing activities resulted from the sale of SPPC's
water business. The increase in cash provided from financing activities resulted
from a reduction in net retirements of short-term debt and proceeds from the
sale of common stock. Cash provided by financing activities was substantially
utilized for the payment of higher energy costs in 2001. See Notes 7 (Common
Stock and Other Paid-in Capital) and 12 (Short-Term Borrowings) for detailed
financing information.
SPR's net cash flows increased in 2000 compared to 1999. The net
increase in cash resulted from less cash used in investing activities offset
substantially by decreases in cash from operating and financing activities. The
decrease in cash flows used in investing activities is due to the merger cash
requirements included in the 1999 amounts. Cash flows from operating activities
were less in 2000 due primarily to a decrease in operating income and an
increase in accounts receivable, offset, in part, by increases in accounts
payable and depreciation and amortization. Cash flows from financing activities
decreased in 2000 compared to 1999 because most of the cash provided by
long-term debt issued in 2000 was utilized to retire short-term borrowings and
other long-term debt. See Notes 9 (Long Term-Debt) and 12 (Short-Term
Borrowings) for detailed financing information.
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 these two subsidiaries are public utilities,
they are subject to regulation by state utility commissions which may impose
limits on investment returns or otherwise impact the amount of dividends which
may be paid by those companies. Moreover, the Articles of Incorporation of SPPC
contain restrictions on the payment of dividends on SPPC's common stock in the
event of a default in the payment of dividends on SPPC's preferred stock.
Similarly, the Credit Agreements of NPC and SPPC prohibit the payment of
dividends on each company's common stock if that company is in default under the
terms of the relevant credit facility. Finally, the terms of certain outstanding
series of first mortgage bonds of both NPC and SPPC limit the cumulative amount
of dividends that may be paid on each company's common stock to the cumulative
net earnings of that company over an extended period of time. Any of these
provisions which potentially restrict dividends payable by NPC or SPPC could
adversely affect liquidity at the SPR level.
In addition to the liquidity provided by dividends from its
subsidiaries, SPR maintains $75 million of short-term liquidity capacity at the
holding company level in the form of a Credit Agreement with the same bank group
that has entered into Credit Agreements with NPC and SPPC. This facility matures
on November 28, 2002 and may be used to provide liquidity for general corporate
purposes including to back up a commercial paper program, although SPR does not
currently maintain a commercial paper program. The Credit Agreement contains a
number of restrictive covenants including restrictions on liens, sales of assets
and mergers or sale and leaseback transactions by SPR or its subsidiaries. The
Credit Agreement also contains financial covenants requiring that SPR maintain:
43
. a ratio of (i) Total Indebtedness to (ii) the sum of Total Indebtedness and
Shareholders Equity that does not exceed 0.65:1 as of the last day of each
fiscal quarter.
. a Consolidated Interest Coverage Ratio of not less than 1.5 to 1 calculated
as of the last day of each fiscal quarter for the preceding four consecutive
fiscal quarters.
As of December 31, 2001, SPR was in compliance with these financial covenants.
The borrowing costs under the Credit Agreement are at a variable
interest rate consisting of a spread over LIBOR or an alternate base rate that
is based upon a pricing grid tied to the credit rating on SPR's senior unsecured
long-term debt. SPR had no borrowings outstanding under the Credit Agreement as
of December 31, 2001. On or before the maturity date of the Credit Agreement,
SPPC currently intends to either renew or replace the Credit Agreement.
Like the Credit Agreements for NPC and SPPC, SPR's Credit Agreement is
unsecured. However, SPR's Credit Agreement does not require the issuance of
collateral to the banks in the event that the credit rating on SPR's long-term
unsecured debt is downgraded.
Construction Expenditures and Financing (SPR Consolidated)
The table below provides SPR's consolidated cash construction
expenditures and internally generated cash, net for 1999 through 2001 (dollars
in thousands):
2001 2000 1999 Total
-------------- ----------- ---------- -------------
Cash construction expenditures $ 302,875 $328,990 $729,794 $1,361,659
============== =========== ========== =============
Net cash flow from operating activities $ (1,045,221) $185,896 $211,089 $ (648,236)
Less common & preferred cash dividends 64,917 83,057 115,833 263,807
-------------- ----------- ---------- -------------
Internally generated cash $ (1,110,138) 102,839 95,256 (912,043)
============== =========== ========== =============
Internally generated cash as a percentage of
cash construction expenditures Not Applicable 31% 13% Not Applicable
* 1999 cash construction expenditures include $448.3 million of merger related
costs.
SPR's estimated cash construction expenditures for 2002 through 2006
are $1.7 billion. Construction expenditures for 2002 (approximately $470
million) will be financed through debt issuance and internally generated funds,
including recovery of deferred energy. It is anticipated that the Utilities will
pay all of their net income in dividends to SPR. SPR anticipates capital
contributions of $16 million to NPC and $60 million to SPPC in 2002. SPPC will
utilize proceeds from the issuance of short-term debt and parent contributions
to fund construction.
Cash provided by internally generated funds during 2002 assumes full
recovery of deferred energy costs over three years for NPC and SPPC. SPR also
assumes general rate increases approved as filed effective at the beginning of
the second quarter and mid-year for NPC and SPPC, respectively. To the extent
that the PUCN finds that any of the Utilities' deferred energy costs resulted
from imprudent purchases, the PUCN will not permit that amount to be recovered
through higher rates, and an equivalent amount of the Utilities' deferred energy
cost asset will be required to be written off. A material write-off of deferred
energy costs would have a material adverse affect on the future results of
operations of SPR and the Utilities and could cause their securities to be
downgraded by the rating agencies and make it significantly more difficult to
finance operations, and buy fuel and purchased power from third parties.
44
If SPR does not receive substantial recovery of deferred energy costs
for the Utilities, depending upon the extent of the disallowance, the rating
agencies might downgrade SPR and its subsidiaries. A downgrade by one or more of
the national rating agencies of the credit rating for the debt of SPR, NPC or
SPPC would affect the companies' liquidity primarily in two principal areas: (1)
their respective financing arrangements and (2) NPC's and SPPC's contracts for
fuel, for purchase and sale of electricity and for transportation of natural
gas.
With respect to the financing arrangements, in the event that either
NPC's or SPPC's commercial paper programs are downgraded, the downgraded issuer
would no longer be able to issue commercial paper, thereby requiring the issuer
to draw upon its back-up credit facility to pay off outstanding commercial paper
balances. With respect to other financing arrangements, a downgrade in and of
itself would not trigger an event of default or otherwise accelerate the payment
obligations under any of SPR's, NPC's or SPPC's financing agreements. However,
the bank Credit Agreements of NPC and SPPC include a "springing lien" feature,
pursuant to which NPC or SPPC would be required, in the event that the company's
senior unsecured debt is downgraded, to issue General and Refunding Mortgage
bonds to the banks in an amount equal to the aggregate principal amount of the
commitments under the facilities. If the springing lien were triggered for NPC,
NPC would likely be obligated, under a negative pledge clause applicable to its
senior unsecured notes, to issue an additional $130 million of General and
Refunding Bonds as collateral for those securities.
With respect to NPC's and SPPC's contracts for purchased power, NPC and
SPPC purchase and sell electricity with their counterparties under the Western
Systems Power Pool ("WSPP") agreement, which is an industry standard contract.
The WSPP contract is posted on the WSPP website. These contracts provide that a
material adverse change may trigger a request for collateral, which, if not
provided within 3 business days, may trigger a default. A request for collateral
must be exercised within 30 days of the event becoming known. A default will
result in a termination payment equal to the present value of the net gains and
losses aggregated to a single liquidated amount due within 3 business days
following the date the notice of termination is received. The mark to market
value can be used to roughly approximate the termination payment at any point in
time.
With respect to the purchase and sale of natural gas, NPC and SPPC use
several types of contracts. Standard industry sponsored agreements include: (1)
the Gas Industry Standards Board ("GSIB") agreement which is used for physical
gas transactions, (2) the GasEDI Base Contract for Short Term Sale and Purchase
of Natural Gas which is also used for physical gas transactions, or (3) the
International Swap Dealers Association (ISDA) agreement which is used for
financial gas transactions. Alternatively, the gas transactions might be
governed by a non-standard bilateral master agreement negotiated between the
parties, or by the confirmation associated with the transaction. The natural gas
contract terms and conditions are more varied than the electric contracts.
Consequently, some of the contracts do not contain rating downgrade triggers and
some contain language similar to that found in the WSPP agreement.
Gas transmission services are provided under the FERC Gas Tariff or a
custom agreement. These contracts require the entities to establish and maintain
creditworthiness to obtain service.
Contractual Obligations (SPR Consolidated)
The table below provides SPR's consolidated contractual obligations,
not including estimated construction expenditures described above, as of
December 31, 2001, 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):
45
Payments Due By Period
2002 2003 2004 2005 2006 Thereafter Total
------------- -------------------------------------------------------------------------------
Long- Term Debt (1) $ 299,010 $ 570,632 $ 132,621 $ 302,622 $ 52,629 $ 2,317,601 $ 3,675,115
Purchased Power 1,348,451 152,852 151,627 136,680 137,446 777,064 2,704,120
Coal and Natural Gas 367,373 126,027 129,482 96,671 94,299 725,651 1,539,503
Capital Lease Obligations 6,156 6,156 6,946 7,736 7,736 58,016 92,746
Operating Leases 12,127 9,284 8,194 7,289 6,863 63,463 107,220
Other Long-Term Obligations 300 300
------------- ------------ ------------ ----------- ----------- -------------- ------------
Total Contractual Cash
Obligations $ 2,033,417 $ 864,951 $ 428,870 $ 550,998 $ 298,973 $ 3,941,795 $ 8,119,004
============= ============ ============ =========== =========== ============== ============
(1) Includes short-term debt of $177,000.
Capital Structure (SPR Consolidated)
SPR's actual consolidated capital structure at December 31, 2001, and
2000 was as follows (dollars in thousands):
2001 2000
------------------------- -----------------------
Short-Term Debt (1) $ 299,010 6% $ 685,601 15%
Long-Term Debt 3,376,105 57% 2,133,679 48%
Preferred Stock 50,000 1% 50,000 1%
Preferred Trust Securities 188,872 4% 237,372 5%
Common Equity 1,702,322 32% 1,359,712 31%
------------------------- --------------------------
TOTAL $5,616,309 100% $ 4,466,364 100%
========================= ==========================
(1) Including current maturities of long-term debt. Included in amounts above
for Long-Term Debt is $600 million of SPR holding company debt.
The merger between SPR and NPC was accounted for as a reverse purchase
under generally accepted accounting principles, with NPC considered the
acquiring entity, even though SPR became the legal parent of NPC. For accounting
purposes, the merger was deemed to have occurred on August 1, 1999. As a result
of this reverse purchase accounting treatment: (i) the historical financial
statements of SPR for periods prior to the date of the merger are no longer the
financial statements of SPR, and therefore, are no longer presented; (ii) the
historical financial statements of SPR for periods prior to the date of the
merger are those of NPC; (iii) based on a merger date of August 1, 1999, the
Consolidating Statements of Income for the twelve months ended December 31,
1999, include five months (August through December 1999) of operating activity
for SPR and its subsidiaries other than NPC and include the operating results of
NPC for the entire periods presented; and (iv) each of the Consolidating
Statements of Income for the twelve months periods ended December 31, 2001 and
2000, include twelve months of operating activity for SPR and its subsidiaries.
46
SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME
(Dollars in Thousands)
Year Ended December 31, 2001
----------------------------------------------------------
12 months 12 months 12 months
NPC SPPC Other Total
---------------------------- ---------------------------
OPERATING REVENUES:
Electric $ 3,025,103 $ 1,399,134 $ - $ 4,424,237
Gas 145,652 - 145,652
Other - - 18,841 18,841
------------- -------------- ------------ --------------
3,025,103 1,544,786 18,841 4,588,730
------------- -------------- ------------ --------------
OPERATING EXPENSES:
Operation:
Purchased power 3,026,336 1,025,741 - 4,052,077
Fuel for power generation 441,900 286,719 - 728,619
Gas purchased for resale - 136,534 - 136,534
Deferral of energy costs-electric-net (937,322) (198,826) - (1,136,148)
Deferral of energy costs-gas-net - (23,170) - (23,170)
Other 169,442 117,627 44,892 331,961
Maintenance 45,136 24,363 - 69,499
Depreciation and amortization 93,101 70,358 1,181 164,640
Taxes: -
Income taxes 17,775 8,507 (27,512) (1,230)
Other than income 24,371 17,965 743 43,079
------------- -------------- ------------ --------------
2,880,739 1,465,818 19,304 4,365,861
------------- -------------- ------------ --------------
OPERATING INCOME 144,364 78,968 (463) 222,869
------------- -------------- ------------ --------------
OTHER INCOME:
Allowance for other funds used during
construction (382) 856 - 474
Other income - net 27,272 8,489 2,962 38,723
------------- -------------- ------------ --------------
26,890 9,345 2,962 39,197
------------- -------------- ------------ --------------
Total Income Before Interest Charges 171,254 88,313 2,499 262,066
------------- -------------- ------------ --------------
INTEREST CHARGES:
Long-term debt 81,599 55,199 51,572 188,370
Other 13,219 7,433 3,509 24,161
Allowance for borrowed funds used during
construction and capitalized interest (2,141) (660) - (2,801)
------------- -------------- ------------ --------------
92,677 61,972 55,081 209,730
------------- -------------- ------------ --------------
INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED
MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 78,577 26,341 (52,582) 52,336
Preferred dividend requirements of obligated mandatorily
redeemable preferred trust securities (15,172) (3,598) - (18,770)
------------- -------------- ------------ --------------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 63,405 22,743 (52,582) 33,566
Preferred stock dividend requirements - (3,700) - (3,700)
------------- -------------- ------------ --------------
INCOME (LOSS) FROM CONTINUING OPERATIONS 63,405 19,043 (52,582) 29,866
INCOME FROM DISCONTINUED OPERATIONS - 1,022 - 1,022
GAIN ON DISPOSAL OF WATER BUSINESS - 25,845 - 25,845
------------- -------------- ------------ --------------
NET INCOME (LOSS) $ 63,405 $ 45,910 $ (52,582) $ 56,733
============= ============== ============ ==============
47
SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME
(Dollars in Thousands)
Year Ended December 31, 2000
----------------------------------------------------------
12 months 12 months 12 months
NPC SPPC Other Total
---------------------------- -----------------------------
OPERATING REVENUES:
Electric $ 1,325,470 $ 893,782 $ - $ 2,219,252
Gas 100,803 - 100,803
Other - - 14,199 14,199
------------- -------------- -------------- --------------
1,325,470 994,585 14,199 2,334,254
------------- -------------- -------------- --------------
OPERATING EXPENSES:
Operation:
Purchased power 671,396 444,979 - 1,116,375
Fuel for power generation 292,787 233,748 - 526,535
Gas purchased for resale - 83,199 - 83,199
Deferral of energy costs-electric-net 16,719 - - 16,719
Deferral of energy costs-gas-net - (16,164) - (16,164)
Other 139,723 96,438 24,335 260,496
Maintenance 34,057 18,420 - 52,477
Depreciation and amortization 85,989 69,350 696 156,035
Taxes:
Income taxes (12,162) (672) (18,188) (31,022)
Other than income 23,501 18,152 562 42,215
------------- -------------- -------------- --------------
1,252,010 947,450 7,405 2,206,865
------------- -------------- -------------- --------------
OPERATING INCOME 73,460 47,135 6,794 127,389
------------- -------------- -------------- --------------
OTHER INCOME:
Allowance for other funds used during
construction 2,456 357 - 2,813
Other income (expense) - net 1,718 (2,429) 3,357 2,646
------------- -------------- -------------- --------------
4,174 (2,072) 3,357 5,459
------------- -------------- -------------- --------------
Total Income Before Interest Charges 77,634 45,063 10,151 132,848
------------- -------------- -------------- --------------
INTEREST CHARGES:
Long-term debt 64,513 36,865 33,218 134,596
Other 13,732 11,312 10,843 35,887
Allowance for borrowed funds used during
construction and capitalized interest (7,855) (2,779) - (10,634)
------------- -------------- -------------- --------------
70,390 45,398 44,061 159,849
------------- -------------- -------------- --------------
INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED
MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 7,244 (335) (33,910) (27,001)
Preferred dividend requirements of obligated mandatorily
redeemable preferred trust securities (15,172) (3,742) - (18,914)
------------- -------------- -------------- --------------
(LOSS) BEFORE PREFERRED STOCK DIVIDENDS (7,928) (4,077) (33,910) (45,915)
Preferred stock dividend requirements - (3,499) - (3,499)
------------- -------------- -------------- --------------
(LOSS) FROM CONTINUING OPERATIONS (7,928) (7,576) (33,910) (49,414)
INCOME FROM DISCONTINUED OPERATIONS - 9,634 - 9,634
------------- -------------- -------------- --------------
NET (LOSS) INCOME $ (7,928) $ 2,058 $ (33,910) $ (39,780)
============= ============== ============== ==============
48
SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME
(Dollars in Thousands)
Year Ended December 31, 1999
---------------------------------------------------------
12 months 5 months 5 months
NPC SPPC Other Total
--------------------------- -----------------------------
OPERATING REVENUES:
Electric $ 977,262 $ 259,440 $ - $ 1,236,702
Gas - 38,958 - 38,958
Other - - 9,132 9,132
------------- ------------- ------------- ---------------
977,262 298,398 9,132 1,284,792
------------- ------------- ------------- ---------------
OPERATING EXPENSES:
Operation:
Purchased power 293,600 79,856 - 373,456
Fuel for power generation 154,546 51,584 - 206,130
Gas purchased for resale - 27,262 - 27,262
Deferral of energy costs-electric-net 97,238 - - 97,238
Other 141,041 40,961 11,389 193,391
Maintenance 50,805 8,492 - 59,297
Depreciation and amortization 80,644 29,188 243 110,075
Taxes:
Income taxes 19,943 10,602 (5,247) 25,298
Other than income 22,462 7,232 90 29,784
------------- ------------- ------------- ---------------
860,279 255,177 6,475 1,121,931
------------- ------------- ------------- ---------------
OPERATING INCOME 116,983 43,221 2,657 162,861
------------- ------------- ------------- ---------------
OTHER INCOME:
Allowance for other funds used during
construction 3,713 (1,374) - 2,339
Other (expense) income - net (1,824) (853) 352 (2,325)
------------- ------------- ------------- ---------------
1,889 (2,227) 352 14
------------- ------------- ------------- ---------------
Total Income Before Interest Charges 118,872 40,994 3,009 162,875
------------- ------------- ------------- ---------------
INTEREST CHARGES:
Long-term debt 64,454 12,741 299 77,494
Other 8,815 5,885 11,529 26,229
Allowance for borrowed funds used during
construction and capitalized interest (8,356) 356 - (8,000)
------------- ------------- ------------- ---------------
64,913 18,982 11,828 95,723
------------- ------------- ------------- ---------------
INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED
MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 53,959 22,012 (8,819) 67,152
Preferred dividend requirements of obligated mandatorily
redeemable preferred trust securities (15,172) (1,570) - (16,742)
------------- ------------- ------------- ---------------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 38,787 20,442 (8,819) 50,410
Preferred stock dividend requirements (95) (2,105) - (2,200)
------------- ------------- ------------- ---------------
INCOME (LOSS) FROM CONTINUING OPERATIONS 38,692 18,337 (8,819) 48,210
INCOME FROM DISCONTINUED OPERATIONS - 3,540 - 3,540
------------- ------------- ------------- ---------------
NET INCOME (LOSS) $ 38,692 $ 21,877 $ (8,819) $ 51,750
============= ============= ============= ===============
49
NEVADA POWER COMPANY
--------------------
Results of Operations
NPC earned net income of $63.4 million in 2001, compared to a net loss of
($7.9) million in 2000, and 1999 net income before dividend requirements on
preferred stock of $38.8 million. These amounts do not include NPC's equity in
the earnings (losses) of SPR. 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
2001 2000 1999
---------------------------- ----------------------------- -------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------- ------------- ------------- ------------- -------------
Electric Operating Revenues:
Residential $ 644,875 31.0% $ 492,365 18.3% $ 416,345
Commercial 302,682 32.9% 227,790 13.8% 200,186
Industrial 447,766 37.0% 326,916 12.6% 290,409
------------- ------------- -------------
Retail revenues 1,395,323 33.3% 1,047,071 15.5% 906,940
Other 1,629,780 485.4% 278,399 295.9% 70,322
------------- ------------- -------------
Total Revenues $ 3,025,103 128.2% $ 1,325,470 35.6% $ 977,262
============= ============= =============
Total retail sales (MWh) 16,799,000 2.7% 16,363,000 12.0% 14,615,000
Average retail revenue per MWh $ 83.06 29.8% $ 63.99 3.1% $ 62.06
NPC's retail revenues increased in 2001 due to a combination of customer
growth, and rate increases resulting from the Global Settlement and
Comprehensive Energy Plan (CEP) (see Major Factors Affecting Results Of
Operations, earlier). The number of residential, commercial, and industrial
customers increased over the prior year by 4.8%, 4.4% and 6.5%, respectively. As
a result of the CEP, a rate increase of 17% for retail customers became
effective March 1, 2001. Substantially all of the increase in Other electric
revenues was due to the sale of wholesale electric power to other utilities.
NPC's increase in wholesale sales compared to 2000 was a result of market
conditions and NPC's power procurement activities. See Purchased Power
Procurement, later, for a discussion of the Utilities' purchased power
procurement strategies.
NPC's retail revenues increased in 2000 due to a combination of customer
growth, warmer than normal weather, and rate increases resulting from the Global
Settlement. The number of residential, commercial, and industrial customers
increased over the prior year by 5.6%, 4.6% and 7.4%, respectively. As a result
of the Global Settlement, NPC implemented monthly rate increases starting August
1, 2000. Other electric revenues were higher in 2000 compared to 1999 due to
increased sales of wholesale electric power to other utilities. See Purchased
Power Procurement, later, for a discussion of the Utilities' purchased power
procurement strategies.
50
Purchased Power
2001 2000 1999
----------------------------- ---------------------------- -------------
Change from Change from
Amount Prior year Amount Prior year Amount
-------------- ------------- ------------ ------------- -------------
Total purchased power $ 3,026,336 350.8% $ 671,396 98.1% $ 338,972
Less imputed capacity deferral - - - - (45,372)
-------------- ------------- -------------
Purchased Power $ 3,026,336 350.8% $ 671,396 128.7% $ 293,600
============== ============= =============
Purchased power MWh 19,268,305 99.5% 9,659,118 22.9% 7,861,985
Average cost per MWh of
purchased power $ 157.06 126.0% $ 69.51 61.2% $ 43.12
NPC's purchased power costs were significantly higher in 2001 due to
substantial increases in prices and volumes. Per unit costs of power increased
126% primarily due to higher Short-Term Firm energy prices. These price
increases were the result of much higher fuel costs, combined with increased
demand and limited power supplies. Volumes purchased rose 100% to accommodate
increases in system load of approximately 2.7% and increases in wholesale sales
of approximately 310%. Purchases associated with risk management activities,
which include transactions entered into for hedging purposes and to optimize
purchased power costs, are included in the purchased power amounts. See
Purchased Power Procurement, later, for a discussion of the Utilities' purchased
power procurement strategies.
Purchased power costs were higher in 2000 as compared to 1999 due to a 23%
increase in the volume purchased and an increase in the per unit cost of power
of 61%.
Fuel for Power Generation
2001 2000 1999
---------------------------- ----------------------------- -------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------- ------------- ------------- ------------- -------------
Fuel for Power Generation $ 441,900 50.9% $ 292,787 89.4% $ 154,546
MWhs generated 9,899,195 -7.9% 10,744,466 17.2% 9,167,963
Average fuel cost per MWh
of generated power $ 44.64 63.8% $ 27.25 61.6% $ 16.86
NPC's 2001 fuel expense increased over 50% compared to 2000 primarily
due to a substantial increase in natural gas prices, offset in part, by
decreased generation late in 2001 when the cost of purchased power was more
economical than generation. In 2000, NPC's fuel expense increased 89% compared
to 1999 primarily due to a substantial increase in natural gas prices.
51
Deferral of Energy Costs - Net
2001 2000 1999
--------------------------- -------------------------- ---------
Change from Change from
Amount Prior year Amount Prior year Amount
----------- -------------- ---------- -------------- ----------
Deferral of energy costs-electric-net $ (937,322) N/A $ 16,719 -82.8% $ 97,238
NPC recorded a significant Deferral of energy costs-net in 2001 due to the
implementation of deferred energy accounting beginning March 1, 2001. The
current year amounts reflect the extent to which actual fuel and purchased power
costs exceeded the fuel and purchased power costs recovered through current
rates. Deferral of energy costs-net for 2000 represents energy costs that had
been deferred in prior periods and were then recovered in 2000, as a result of
deferred energy rate increases granted in 1999.
Deferral of energy costs-net decreased in 2000 compared to 1999 because NPC
discontinued deferred energy cost accounting effective August 1, 2000, pursuant
to the July 2000 Global Settlement with the PUCN, and because of decisions,
described below, by the PUCN affecting 1999's Deferral of energy costs-net. For
more information on the Global Settlement, see Major Factors Affecting Results
Of Operations, earlier.
In February and March 2000, the PUCN issued orders that rejected NPC's
requested rate relief in its 1999 deferred energy filings. As a result of these
decisions, a pre-tax charge of $80 million to Deferral of energy costs-net was
made in 1999 to write-off deferred energy and imputed capacity costs.
See "Critical Accounting Policies," earlier, and Note 1 of "Notes to
Financial Statements" for more information regarding deferred energy accounting.
Allowance For Funds Used During Construction (AFUDC)
2001 2000 1999
-------------------------- --------------------------- ----------
Change from Change from
Amount Prior year Amount Prior year Amount
---------- -------------- ---------- --------------- ----------
Allowance for other funds used
during construction $ (382) -115.6% $ 2,456 -33.9% $ 3,713
Allowance for borrowed funds used
during construction 2,141 -72.7% 7,855 -6.0% 8,356
------- -------- --------
$ 1,759 -82.9% $ 10,311 -14.6% $ 12,069
------- -------- --------
NPC AFUDC is lower in 2001 because of adjustments to amounts assigned to
specific components of facilities that were completed in different periods. In
2000, there was a small decrease in the AFUDC rate compared to 1999 because of
an increase in short-term debt.
52
Other Expenses
2001 2000 1999
------------------------------ --------------------------- ------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------ -------------- ------------ ------------- ------------
Other operating expense $ 169,442 21.3% $ 139,723 -0.9% $ 141,041
Maintenance expense 45,136 32.5% 34,057 -33.0% 50,805
Depreciation and amortization 93,101 8.3% 85,989 6.6% 80,644
Income taxes 17,775 N/A (12,162) -161.0% 19,943
Interest charges on long-term debt 81,599 26.5% 64,513 0.1% 64,454
Interest charges- other 13,219 -3.7% 13,732 55.8% 8,815
Other income (expense)-net 27,272 1487.4% 1,718 -194.2% (1,824)
Other operating expense increased in 2001 compared to 2000 due to a $16.6
million larger addition to the provision for uncollectible customer accounts
than in 2000, reflecting the impact of the weakening economy and disruption to
the leisure travel industry after September 11, 2001. Other operating expense
also increased due to the addition of $12.6 million to the uncollectible
provision related to receivables from the California Power Exchange (PX) and
California's Independent System Operator (ISO). NPC's other operating expense
for 2000 was $8.8 million lower than 1999 due to reduced labor and benefit costs
as a result of merger efficiencies and unfilled vacancies. These savings were
offset, in part, by an increase in the provision for uncollectible accounts that
included a provision of $7.3 million related to the PX and ISO.
The level of NPC's maintenance and repair expenses depends primarily upon
the scheduling, magnitude and number of generation unit overhauls at NPC's
generating stations. Maintenance expense for 2001 increased from the prior year
as a result of increased outage work at Reid-Gardner, additional expenditures
for repairs and outages at Clark Station and increased work at Mohave. In 2000
maintenance expense decreased from the prior year primarily as a result of fewer
planned plant maintenance activities at NPC's coal generation facilities. In
addition, in 2000 crews performed required activities of a capital nature,
thereby reducing the amount of maintenance expense.
An increase in plant-in-service was the cause of NPC's increase in
depreciation and amortization expense in 2001 compared to 2000. Depreciation and
amortization was also higher in 2000 than 1999 due to an increase in
plant-in-service.
As a result of net income for 2001, NPC incurred income tax expense. Due to
a net loss in 2000, NPC recorded an income tax benefit for the year. See Note 10
of "Notes to Financial Statements" for additional information regarding the
computation of income taxes.
NPC's interest charges on long-term debt increased in 2001 compared to
2000, following a net increase in associated debt of $450 million (new issuances
of $700 million and redemptions of $250 million during 2001). Interest charges
on long-term debt for 2000 were comparable to 1999s. See Note 9 of "Notes to
Financial Statements" for additional information regarding long-term debt.
NPC's interest charges-other in 2001 were comparable to 2000. Interest
charges-other increased in 2000 compared to 1999 due to increased debt through
the issuance of commercial paper in 2000 and due to interest costs associated
with the issuance of floating rate notes in October 1999 and June, August, and
December 2000.
NPC's other income (expense) - net improved in 2001 due primarily to the
recognition in the current year of carrying charges on deferred fuel and
purchased power balances pursuant to AB 369. Other income
53
(expense)-net improved in 2000 over the prior year as a result of greater
increases in life insurance cash surrender values and reductions in
contributions and membership dues.
Liquidity and Capital Resources
NPC's net cash flows decreased in 2001 compared to 2000. The net decrease
in cash resulted from a significant increase in cash flows used in operating
activities combined with cash used in investing activities both partially offset
by an increase in cash provided by external financing sources. The increase in
cash flows used in operating activities resulted substantially from the payment
of significantly higher energy costs during 2001. Net cash used in investing
activities was comparable between 2001 and 2000. Net cash provided by financing
activities was higher in 2001 as a result of cash provided by the issuance of
short-term and long-term debt, as described in Notes 12 and 9 to the Financial
Statements, and additional capital contributions from SPR. Cash provided by
financing activities was substantially utilized for the payment of higher energy
costs in 2001.
NPC's net cash flows increased in 2000 compared to 1999. The net increase
in cash resulted from less cash used in investing activities and more cash
provided by financing activities. A reduction in the net cash used for utility
plant was the main cause for the decrease in cash used for investing activities.
The increase in cash flows from financing activities was due to an increase in
funding received from SPR (less dividends paid) offset, in part, by less cash
provided by the net issuance of long and short-term debt. The overall net
increase in cash was also partially offset by a reduction in cash received from
operating activities that was mainly due to a decrease in operating income.
As discussed in "Construction Expenditures and Financing" and "Capital
Structure" that follow, NPC anticipates external capital requirements for
construction costs and for the repayment of maturing short-term and long-term
debt during 2002 totaling approximately $403 million, which NPC will fund
through a combination of (i) internally generated funds, (ii) the issuance of
short-term debt and preferred stock, and (iii) capital contributions from SPR.
NPC's primary source of short-term liquidity has been its commercial paper
program, pursuant to which it sells commercial paper of varying maturities
through dealers to institutional purchasers of commercial paper. NPC's current
program permits the sale of up to $200 million of commercial paper on a
revolving basis. As of December 31, 2001, NPC had $130.5 million of commercial
paper outstanding, representing all of NPC's short-term debt as of that date. As
is customary for an A2/P2 commercial paper issuer, NPC's commercial paper
program requires that NPC maintain a back-up credit facility in the event that
NPC is unable to sell additional commercial paper to pay off outstanding
commercial paper due to conditions within the commercial paper market or due to
a downgrade in the credit rating of NPC's commercial paper. Accordingly, if
there ever were an event of default under or cancellation or termination of the
back-up credit facility, NPC would not be able to issue commercial paper until
NPC obtained another back-up credit facility or until the default were waived or
cured.
As discussed in "Capital Structure" below, NPC has a Credit Agreement with
a number of banks which matures on November 28, 2002. Although this facility may
be used to provide liquidity for general corporate purposes, it has been used
primarily by NPC to back up its commercial paper program. The Credit Agreement
contains a number of restrictive covenants including restrictions on liens,
sales of assets, mergers, and sale and leaseback transactions. The Credit
Agreement also contains financial covenants requiring that NPC maintain:
. a ratio of (i) Total Indebtedness to (ii) the sum of Total Indebtedness and
Shareholders Equity that does not exceed 0.60:1 as of the last day of each
fiscal quarter.
. a Consolidated Interest Coverage Ratio of not less than 2.0:1 calculated as
of the last day of each fiscal quarter for the preceding four consecutive
fiscal quarters.
54
As of December 31, 2001, NPC was in compliance with these financial covenants.
The borrowing costs under the Credit Agreement are at a variable interest
rate consisting of a spread over LIBOR or an alternate base rate that is based
upon a pricing grid tied to the credit rating on NPC's senior unsecured
long-term debt. NPC had no borrowings outstanding under the Credit Agreement as
of December 31, 2001. On or before the maturity date of the Credit Agreement,
NPC currently intends to either renew or replace the Credit Agreement.
The Credit Agreement is currently unsecured. However, NPC will be required
to secure the Credit Agreement through the issuance of General and Refunding
Mortgage bonds to the lenders in the event that the credit rating on NPC's
senior unsecured long-term debt is downgraded (i) by Moody's Investors Service,
Inc. to Baa3 or lower or (ii) by Standard & Poor's Ratings Group to BB+ or
lower. The Credit Agreement requires NPC to maintain sufficient capacity under
its General and Refunding Mortgage Indenture to satisfy this collateral
requirement.
NPC and SPPC are currently negotiating receivables purchase facilities, in
an aggregate principal amount not to exceed $200 million, that are expected to
be finalized by the end of first quarter 2002. Under the proposed facilities,
NPC and SPPC would each sell receivables in a true sale to special purpose
entities that would in-turn sell those assets to a commercial paper conduit that
would pay for the purchase of the assets by issuing commercial paper. These
facilities will be used to provide additional liquidity for working capital and
general corporate purposes in addition to NPC's existing commercial paper
program. NPC expects the facility to be accounted for in compliance with SFAS
No. 140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities." The special purpose entities will be wholly
owned subsidiaries and their financial positions and results of operations will
be reflected in the consolidated financial statements of SPR, NPC, and SPPC.
NPC's first mortgage indenture creates a first priority lien on
substantially all of NPC's properties. As of December 31, 2001, $387.5 million
of NPC's first mortgage bonds were outstanding. Although the first mortgage
indenture allows NPC to issue additional mortgage bonds on the basis of (i) 60
percent of net utility property additions and/or (ii) the principal amount of
retired mortgage bonds, NPC agreed in its General and Refunding Mortgage
Indenture that it would limit the issuance of additional first mortgage bonds to
not more than $80 million.
NPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of NPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of December 31, 2001, $490 million of NPC's
General and Refunding Mortgage securities were outstanding. Additional
securities may be issued under the General and Refunding Mortgage Indenture on
the basis of (i) 70 percent of net utility property additions, (ii) the
principal amount of retired General and Refunding Mortgage bonds and/or (iii)
the principal amount of first mortgage bonds retired after delivery to the
indenture trustee of the initial expert's certificate under the General and
Refunding Mortgage Indenture. At December 31, 2001, NPC had the capacity to
issue approximately $1.2 billion of additional General and Refunding Mortgage
bonds. However, the financial covenants contained in the Credit Agreement
described above may limit NPC's ability to issue additional general and
refunding bonds or other debt.
NPC also has the ability to release property from the liens of the two
mortgage indentures 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 bonds issuable under
that indenture. Under the terms of NPC's $130 million of 6.20% Senior Unsecured
Notes due 2004, NPC may be required, upon the issuance of additional General and
Refunding Mortgage bonds, to secure the Senior Unsecured Notes through the
issuance of an equal principal amount of General and Refunding Mortgage bonds.
55
Construction Expenditures and Financing
The table below provides NPC's consolidated cash construction expenditures
and internally generated cash, net for 1999 through 2001 (dollars in thousands):
2001 2000 1999 Total
---------- --------- --------- ----------
Cash construction expenditures $ 196,896 $ 196,636 $ 220,919 $ 614,451
========== ========= ========= ==========
Net cash flow from operating activities $ (757,402) $ 113,711 $ 178,178 $ (465,513)
Less common & preferred cash dividends 33,014 88,308 121,646 242,968
---------- --------- --------- ----------
Internally generated cash (790,416) 25,403 56,532 (708,481)
Add equity contribution from parent 474,921 137,000 18,000 629,921
---------- --------- --------- ----------
Total cash available $ (315,495) $ 162,403 $ 74,532 $ (78,560)
========== ========= ========= ==========
Internally generated cash as a percentage of
cash construction expenditures Not Applicable 13% 26% Not Applicable
Total cash generated (used) as a percentage of
cash construction expenditures Not Applicable 83% 34% Not Applicable
----------------------------------------------------------------------------------------------------------------------
NPC's estimated cash construction expenditures for 2002 through 2006 are
$1.118 billion. Construction expenditures for 2002 (approximately $311 million)
will be financed through debt issuance and internally generated funds, including
recovery of deferred energy. In 2002, NPC expects to pay all of its net income
in dividends to SPR and to receive $16 million of capital contribution from SPR.
Cash provided by internally generated funds during 2002 assumes full
recovery of deferred energy over three years and general rate increases approved
as filed effective at the beginning of the second quarter. To the extent that
the PUCN finds that any of NPC's deferred energy costs resulted from imprudent
purchases, the PUCN will not permit that amount to be recovered through higher
rates, and an equivalent amount of NPC's deferred energy cost asset will be
required to be written off. A material write-off of deferred energy costs would
have a material adverse affect on the future results of operations of NPC and
could cause NPC's securities to be downgraded by the rating agencies and make it
significantly more difficult to finance operations, and buy fuel and purchased
power from third parties. Also see Construction Expenditures and Financing (SPR
Consolidated) earlier.
Contractual Obligations
The table below provides NPC's contractual obligations, not including
estimated construction expenditures described above, as of December 31, 2001,
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 and
preferred stock (dollars in thousands):
56
Payments Due By Period
2002 2003 2004 2005 2006 Thereafter Total
---------- --------------------------------------------------------------------------------
Long- Term Debt (1) $ 149,880 $ 350,000 $ 130,000 $ - $ - $1,127,967 $1,757,847
Purchased Power 1,046,893 17,061 109,904 109,374 108,996 713,711 2,105,939
Coal and Natural Gas 187,663 55,493 63,780 31,043 31,064 373,228 742,271
Capital Lease
Obligations 6,156 6,156 6,946 7,736 7,736 58,016 92,746
Operating Leases 2,941 1,470 1,090 926 504 - 6,931
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Contractual Cash
Obligations $1,393,533 $ 430,180 $ 311,720 $ 149,079 $ 148,300 $2,272,922 $4,705,734
========== ========== ========== ========== ========== ========== ==========
(1) Includes short-term debt of $130,500.
Capital Structure
As of December 31, 2001, NPC had short-term debt outstanding of $130.5
miion comprised entirely of commercial paper.
On November 29, 2001, NPC put into place a $200 million unsecured revolving
credit facility replacing an existing $250 million credit facility, which may be
used for working capital and general corporate purposes, including commercial
paper backup. This new credit facility requires NPC to issue general and
refunding mortgage bonds to secure this credit facility in the event of a
decline in NPC's senior unsecured debt rating. This facility will expire on
November 28, 2002.
NPC's actual consolidated capital structure at December 31, 2001, and 2000
was as follows (dollars in thousands):
2001 2000
------------------------- -----------------------
Short-Term Debt (1) $ 149,880 4% $ 352,910 15%
Long-Term Debt 1,607,967 48% 927,784 39%
Preferred Trust Securities 188,872 6% 188,872 8%
Common Equity (2) 1,393,063 42% 887,737 38%
------------------------- -----------------------
TOTAL $3,339,782 100% $2,357,303 100%
========================= =======================
(1) Including current maturities of long-term debt.
(2) Does not include equity in Sierra Pacific Resources: 2001 = $309,259; 2000
= $471,975.
SIERRA PACIFIC POWER COMPANY
----------------------------
Results of Operations
SPPC's operating results that follow are based upon the Sierra Pacific
Power Company Consolidated Statements of Income included in Item 8 of this
report. SPPC's 2001 net income from continuing operations before dividend
requirements on preferred stock was $22.7 million, compared to a net loss in
2000 of ($4.1) million and net income of $64.6 million in 1999.
As described in Note 17, Discontinued Operations, SPPC closed the sale of
its water utility business on June 11, 2001. Accordingly, the water business is
reported as a discontinued operation and the continuing operating results have
been reclassified to report separately the net results of operations from the
water business.
57
The components of gross margin are (dollars in thousands):
2001 2000 1999
--------------- --------------- ---------------
Operating Revenues:
Electric $ 1,399,134 $ 893,782 $ 609,197
Gas 145,652 100,803 100,177
--------------- --------------- ---------------
Total Revenues 1,544,786 994,585 709,374
--------------- --------------- ---------------
Energy Costs:
Electric 1,113,634 678,727 294,846
Gas 113,364 67,035 68,125
--------------- --------------- ---------------
Total Energy Costs 1,226,998 745,762 362,971
--------------- --------------- ---------------
Gross Margin $ 317,788 $ 248,823 $ 346,403
=============== =============== ===============
Gross Margin by Segment:
Electric $ 285,500 $ 215,055 $ 314,351
Gas 32,288 33,768 32,052
--------------- --------------- ---------------
Total $ 317,788 $ 248,823 $ 346,403
=============== =============== ===============
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
2001 2000 1999
--------------------------- --------------------------- ------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------ ------------ ------------ ------------ ------------
Electric Operating Revenues:
Residential $ 210,350 17.7% $ 178,701 4.2% $ 171,533
Commercial 243,883 23.9% 196,846 4.5% 188,348
Industrial 253,936 29.5% 196,143 5.6% 185,771
------------ ------------ ------------
Retail revenues 708,169 23.9% 571,690 4.8% 545,652
Other 690,965 114.5% 322,092 406.9% 63,545
------------ ------------ ------------
Total Revenues $ 1,399,134 56.5% $ 893,782 46.7% $ 609,197
============ ============ ============
Total retail sales (MWh) 8,729,173 -0.9% 8,807,332 4.7% 8,412,853
------------ ------------ ------------
Average retail revenue per MWh $ 81.13 25.0% $ 64.91 0.1% $ 64.86
The increase in SPPC's 2001 retail revenues was primarily due to rate
increases resulting from the Global Settlement and CEP - see Major Factors
Affecting Results Of Operations, earlier. These rate increases partially offset
the increases in fuel and purchased power costs that SPPC had incurred. Also
contributing to the higher revenues was an increase in the number of
residential, commercial and industrial customers of 2.8%, 3.3% and 9.3%,
respectively. Substantially all of the increase in Other electric revenues was
due to the sale of wholesale electric power to other utilities. SPPC's increase
in wholesale sales compared to 2000 was a result of market conditions and SPPC's
power procurement activities. See Purchased Power Procurement, later, for a
discussion of the Utilities' purchased power procurement strategies.
58
In 2000, as a result of the Global Settlement, retail revenues were $2.9
million higher than 1999 because the PUCN allowed SPPC to begin recovering its
increases in fuel and purchased power costs. The increases in residential and
commercial electric revenues in 2000 were also due to warmer weather during the
cooling-season than in 1999 and, to a lesser extent, by increases in the number
of customers. Industrial revenues increased because of significant increases in
usage per customer, primarily by mining customers. Other electric revenues were
higher due to an increase in wholesale electric sales. See Purchased Power
Procurement, later, for a discussion of the Utilities' purchased power
procurement strategies.
Gas Operating Revenues
2001 2000 1999
--------------------------- --------------------------- ------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------ ------------ ------------ ------------ ------------
Gas Operating Revenues:
Residential $ 63,815 46.6% $ 43,541 1.5% $ 42,888
Commercial 30,680 43.6% 21,368 0.5% 21,259
Industrial 17,941 58.7% 11,307 0.5% 11,252
Wholesale 33,298 46.0% 22,805 -2.8% 23,473
Miscellaneous (82) -104.6% 1,782 36.6% 1,305
------------ ------------ ------------
Total Revenues $ 145,652 44.5% $ 100,803 0.6% $ 100,177
============ ============ ============
Sales (Decatherms) 17,099,787 -8.9% 18,760,851 -21.2% 23,812,031
Average revenues per decatherm $ 8.52 58.7% $ 5.37 27.6% $ 4.21
Gas revenues rose in 2001, primarily due to the fact that the PUCN allowed
SPPC to implement two gas rate increases (see Regulation and Rate Proceedings).
These increases were the result of higher gas costs that SPPC incurred. Revenues
were also higher due to increases of 5.0%, 3.1% and 10.6%, respectively, in
residential, commercial and industrial customers, and an increase in wholesale
revenues.
Residential, commercial and industrial gas revenues in 2000 were comparable
to 1999. Increases from customer growth were largely offset by lower usage as a
result of milder temperatures during the heating seasons. Overall, wholesale gas
sales declined slightly in 2000 compared to 1999. A decline in wholesale volume
was the result of less gas available for wholesale sales because of significant
increases in the usage of gas supplies for electricity generation. This decline
was nearly offset by an increase in wholesale unit prices.
Purchase Power
2001 2000 1999
--------------------------- --------------------------- ------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------ ------------ ------------ ------------ ------------
Purchased Power $ 1,025,741 130.5% $ 444,979 147.5% $ 179,781
Purchased Power MWH 7,591,000 3.3% 7,349,000 26.8% 5,797,903
Average cost per MWH of
Purchased Power $ 135.13 123.2% $ 60.55 95.3% $ 31.01
Purchased power costs increased dramatically in 2001 due to Short-Term Firm
purchase power prices doubling. Purchased power costs also reflect a 14%
increase in wholesale sales. Purchases associated with risk management
activities, which include transactions entered into for hedging purposes and to
optimize purchased power costs, are included in the purchased power amounts. See
Purchased Power Procurement, later, for a discussion of the Utilities' purchased
power procurement strategies.
59
Purchased power costs were higher in 2000 than 1999 primarily because
prices per MWh were double that of the prior year and purchased power was relied
on to accommodate increased system load. Purchased power costs were also higher
during 2000 due to hedging activities in response to higher purchased power
prices.
Fuel For Power Generation
2001 2000 1999
---------------------------- ----------------------------- --------------
Change from Change from
Amount Prior year Amount Prior year Amount
-------------- ------------- -------------- ------------- --------------
Fuel for Power Generation $ 286,719 22.7% $ 233,748 103.1% $ 115,065
MWHs generated 5,985,779 4.0% 5,756,000 15.2% $ 4,998,140
Average fuel cost per MWH
of Generated Power $ 47.90 18.0% $ 40.61 76.4% $ 23.02
Fuel for power generation costs increased 22.7% in 2001 due mainly to
increased natural gas prices, and, to a lesser extent, because volumes purchased
were higher to accommodate greater system load.
Fuel for generation costs in 2000 were higher than 1999 due to higher
gas prices and an increase in volumes purchased.
Gas Purchased for Resale
2001 2000 1999
---------------------------- ----------------------------- --------------
Change from Change from
Amount Prior year Amount Prior year Amount
-------------- ------------- ----------- ------------- ------------
Gas Purchased for Resale $ 136,534 64.1% $ 83,199 22.1% $ 68,125
Gas Purchased for Resale (decatherms) 16,756,970 -9.2% 18,457,112 -22.9% 23,925,940
Average cost per decatherm $ 8.15 80.7% $ 4.51 58.2% $ 2.85
The cost of gas purchased for resale increased in 2001 because a decrease
in the quantities of gas purchased was more than offset by large increases in
unit prices. The decrease in quantities purchased was the result of increased
plant consumption of gas, thereby decreasing the availability of gas for
wholesale activities. The significant gas price increases are consistent with
the regional growth in demand for limited supplies of natural gas.
The cost of gas purchased for resale increased in 2000 because the decrease
in quantities of gas purchased was again more than offset by large increases in
unit prices. The decrease in quantities purchased corresponded to reduced demand
by SPPC's retail customers and reduced availability of gas for wholesale sales
as a result of increased power plant consumption of gas. The higher unit prices
were attributable to increased demand for gas in the Pacific Northwest and
additional transportation fees.
60
Deferral of Energy Cost - Net
2001 2000 1999
---------------------------- ---------------------------- --------------
Change from Change from
Amount Prior year Amount Prior year Amount
--------------- ------------ --------------- ----------- --------------
Deferred energy costs - electric $ (198,826) N/A $ - N/A -
Deferred energy costs - gas (23,170) 43.3% (16,164) N/A -
--------------- --------------- --------------
Total $ (221,996) N/A $ (16,164) N/A $ -
=============== =============== ==============
For 2001, SPPC recorded significant Deferral of energy costs electric-net
(for purchased power and fuel for generation) due to the implementation of
deferred energy accounting beginning March 1, 2001. The current year amounts
reflect the extent to which actual fuel and purchased power costs exceeded the
fuel and purchased power costs recovered through current rates. SPPC did not
utilize deferred energy accounting for its electric operations in 2000 or 1999.
Recovery of fuel expenses is administered under Nevada's deferred energy
cost accounting procedures. Under the deferred energy procedure, changes in the
costs of fuel and purchased power are reflected in customer rates through annual
rate adjustments and do not affect income. See "Critical Accounting Policies,"
earlier, and Note 1 of "Notes to Financial Statements" for more information
regarding deferred energy accounting.
In January 2000, after the expiration of a rate freeze that was in effect
from 1997 through 1999, SPPC began deferring natural gas costs in excess of that
allowed in the tariff for its gas LDC. The deferral increased significantly in
2001 due to higher gas costs incurred by SPPC, as discussed in "Gas Purchased
for Resale," above.
Allowance For Funds Used During Construction (AFUDC)
2001 2000 1999
---------------------------- --------------------------- --------------
Change from Change from
Amount Prior year Amount Prior year Amount
--------------- ----------- -------------- ----------- --------------
Allowance for other funds used
during construction $ 856 139.8% $ 357 N/A $ (1,370)
Allowance for borrowed funds used
during construction 660 -76.3% 2,779 1870.9% 141
--------------- --------------- --------------
$ 1,516 -51.7% $ 3,136 N/A $ (1,229)
--------------- --------------- --------------
SPPC's AFUDC is lower in 2001 because of adjustments to amounts assigned
to specific components of facilities that were completed in different periods
offset by an increase in the AFUDC rate. AFUDC for 2000 is higher than 1999
because of an AFUDC rate increase in 2000 and a $2.3 million adjustment in
1999 to reverse amounts previously charged to AFUDC.
61
Other Expenses
2001 2000 1999
---------------------------- ------------------------- -----------
Change from Change from
Amount Prior year Amount Prior year Amount
----------- --------------- ----------- ------------ -----------
Other operating expense $ 117,627 22.0% $ 96,438 4.0% $92,745
Maintenance expense 24,363 32.3% 18,420 -9.3% 20,309
Depreciation and amortization 70,358 1.5% 69,350 -0.6% 69,762
Income taxes 8,507 N/A (672) -102.0% 33,870
Interest charges on long-term debt 55,199 49.7% 36,865 18.3% 31,151
Interest charges- other 7,433 -34.3% 11,312 0.2% 11,286
Other income (expense)-net 8,489 N/A (2,429) 260.9% (673)
Other operating expense increased in 2001 compared to 2000 due to a $7
million larger addition to the provision for uncollectible customer accounts
than in 2000, and a $3.5 million reserve provision established as a result of AB
369. Additionally, there were increased expenses related to the start-up of the
Pinon Gasifier in 2001. Other operating expense for 2000 was higher due to an
increase in the provision for uncollectible accounts offset, in part, by reduced
labor and benefit costs as a result of merger efficiencies and unfilled
vacancies.
Maintenance costs in 2001 were higher due to additional turbine repairs and
no major overhauls in 2000 at Valmy. There was also a shift from divestiture in
2000 to maintenance activities in 2001 at Tracy as well as unplanned maintenance
on the diesel generators. Maintenance expense for 2000 decreased from 1999 as a
result of fewer outages and lower plant maintenance expenses.
Depreciation and amortization was higher in 2001 than 2000 due to an
increase in plant-in-service. Depreciation and amortization decreased in 2000
from 1999 because of computer software that was fully amortized in 1999.
As a result of recorded income for continuing operations for 2001, SPPC
incurred income tax expense. Due to a net loss from continuing operations, SPPC
recorded an income tax benefit for 2000. See Note 10 of "Notes to Financial
Statements" for additional information regarding the computation of income
taxes.
SPPC'S interest charges on long-term debt were higher in 2001 than 2000,
primarily due to the issuance of $320 million of its General and Refunding
Mortgage bonds in May 2001. Interest charges on long-term debt were higher in
2000, as a result of increased average long-term debt balances compared to 1999,
including the June 2000 issuance of $200 million of variable rate notes.
SPPC'S interest charges-other decreased in 2001 compared to 2000 due to a
decrease in commercial paper balances in 2001. For the year 2000, these interest
charges-other were comparable to 1999.
SPPC's other income (expense) - net improved in 2001 due primarily to the
recognition in the current year of carrying charges on deferred fuel and
purchased power balances pursuant to AB 369. SPPC's other income (expense)-net
declined in 2000 mainly due to the reclassification of lease expenses for SPPC's
main offices.
62
Discontinued Operations
2001 2000 1999
---------------------------- --------------------------- ------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------ -------------- ------------ ------------ ------------
Income from operations of water business $ 1,022 -89.4% $ 9,634 46.3% $ 6,583
Income from operations of the water business decreased in 2001 as a result
of the sale of the water business on June 11, 2001, prior to the seasonal
increase in revenues resulting from higher water send-out. Income from
operations of the water business increased in 2000 due primarily to higher
revenues, which resulted from both customer growth and to a lesser extent higher
usage per customer.
Liquidity and Capital Resources
SPPC's net cash flows during 2001 were comparable to 2000. For 2001, an
increase in net cash flows from investing activities was substantially offset by
a decrease in net cash flows from operating activities. The increase in net cash
flows from investing activities resulted from the sale of the assets of SPPC's
water business. The decrease in cash flows from operating activities resulted
substantially from the payment of significantly higher energy and resale natural
gas costs. These uses of cash flows were partially offset by a decrease in
accounts payable in 2001. The decrease in cash flows from financing activities
was due to reduced reliance on commercial paper in 2001 and the retirement of
preferred stock as described in Note 8 to the Financial Statements offset, in
part, by capital contributions from SPR.
SPPC's net cash flows increased in 2000 compared to 1999. The net increase
in cash resulted from less cash used in investing activities and more cash
provided by financing activities. The decrease in cash used for investing
activities was primarily due to SPPC's 1999 acquisition of General Electric
Capital Corporation's interest in Pinon Pine Company L.L.C. Cash flows from
financing activities increased slightly compared to the prior year due to the
retirement of preferred stock in 1999. See Note 8 (Preferred Stock and Preferred
Trust Securities) for information concerning the preferred stock retirement.
As discussed in "Construction Expenditures and Financing" and "Capital
Structure" below, SPPC will have capital requirements for construction costs and
for the repayment of maturing short-term and long-term debt during 2002 totaling
approximately $189 million, which SPPC will need to fund through a combination
of (i) internally generated funds, (ii) the issuance of short-term debt, and
(iii) capital contributions from SPR.
SPPC's primary source of short-term liquidity has been its commercial paper
program, pursuant to which it sells commercial paper of varying maturities
through dealers to institutional purchasers of commercial paper. SPPC's current
program permits the sale of up to $150 million of commercial paper on a
revolving basis. As of December 31, 2001, SPPC had $46.5 million of commercial
paper outstanding, representing all of SPPC's short-term debt as of that date.
As is customary for an A2/P2 commercial paper issuer, SPPC's commercial paper
program requires that SPPC maintain a back-up credit facility in the event that
SPPC is unable to sell additional commercial paper to pay off outstanding
commercial paper due to conditions within the commercial paper market or due to
a downgrade in the credit rating of SPPC's commercial paper. Accordingly, if
there ever were an event of default under or cancellation or termination of the
back-up credit facility, SPPC would not be able to issue commercial paper until
SPPC obtained another back-up credit facility or until the default were waived
or cured.
As discussed in "Capital Structure" below, SPPC has a Credit Agreement with
a number of banks which matures on November 28, 2002. Although this facility may
be used to provide liquidity for general corporate purposes, it has been used
primarily by SPPC to back up its commercial paper program. The Credit Agreement
63
contains a number of restrictive covenants including restrictions on liens,
sales of assets, mergers, and sale and leaseback transactions. The Credit
Agreement also contains financial covenants requiring that SPPC maintain:
. a ratio of (i) Total Indebtedness to (ii) the sum of Total Indebtedness
and Shareholders Equity that does not exceed 0.60:1 as of the last day of
each fiscal quarter.
. a Consolidated Interest Coverage Ratio of not less than 2.0:1 calculated
as of the last day of each fiscal quarter for the preceding four
consecutive fiscal quarters.
As of December 31, 2001, SPPC was in compliance with these financial covenants.
The borrowing costs under the Credit Agreement are at a variable interest
rate consisting of a spread over LIBOR or an alternate base rate that is based
upon a pricing grid tied to the credit rating on SPPC's senior unsecured
long-term debt. SPPC had no borrowings outstanding under the Credit Agreement as
of December 31, 2001. On or before the maturity date of the Credit Agreement,
SPPC currently intends to either renew or replace the Credit Agreement.
The Credit Agreement is currently unsecured. However, SPPC will be required
to secure the Credit Agreement through the issuance of General and Refunding
Mortgage bonds to the lenders in the event that the credit rating on SPPC's
senior unsecured long-term debt is downgraded (i) by Moody's Investors Service,
Inc. to Baa3 or lower or (ii) by Standard & Poor's Ratings Group to BB+ or
lower. The Credit Agreement requires SPPC to maintain sufficient capacity under
its General and Refunding Mortgage Indenture to satisfy this collateral
requirement.
SPPC and NPC are currently negotiating receivables purchase facilities, in
an aggregate principal amount not to exceed $200 million, that are expected to
be finalized by the end of first quarter 2002. Under the proposed facilities,
SPPC and NPC would each sell receivables in a true sale to special purpose
entities that would in-turn sell those assets to a commercial paper conduit that
would pay for the purchase of the assets by issuing commercial paper. These
facilities will be used to provide additional liquidity for working capital and
general corporate purposes in addition to SPPC's existing commercial paper
program. SPPC expects the facility to be accounted for in compliance with SFAS
No. 140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities." The special purpose entities will be wholly
owned subsidiaries and their financial positions and results of operations will
be reflected in the consolidated financial statements of SPR, NPC, and SPPC.
SPPC's first mortgage indenture creates a first priority lien on
substantially all of SPPC's properties in Nevada and California. As of December
31, 2001, $509.7 million of SPPC's first mortgage bonds were outstanding.
Although the first mortgage indenture allows SPPC to issue additional mortgage
bonds on the basis of (i) 60 percent of net utility property additions and/or
(ii) the principal amount of retired mortgage bonds, SPPC agreed in its General
and Refunding Mortgage Indenture that it would not issue any additional first
mortgage bonds.
SPPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of SPPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of December 31, 2001, $320 million of SPPC's
General and Refunding Mortgage bonds were outstanding. Additional securities may
be issued under the General and Refunding Mortgage Indenture on the basis of (i)
70 percent of net utility property additions, (ii) the principal amount of
retired General and Refunding Mortgage bonds and/or (iii) the principal amount
of first mortgage bonds retired after delivery to the indenture trustee of the
initial expert's certificate under the General and Refunding Mortgage Indenture.
At December 31, 2001, SPPC had the capacity to issue approximately $416 million
of additional General and Refunding Mortgage bonds. However, the financial
covenants contained in the Credit Agreement described above may limit SPPC's
ability to issue additional General and Refunding bonds or other debt.
64
SPPC also has the ability to release property from the liens of the two
mortgage indentures 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 bonds issuable under
that indenture.
Construction Expenditures and Financing
The table below provides SPPC's consolidated cash construction expenditures
and internally generated cash, net for 1999 through 2001 (dollars in thousands):
2001 2000 1999 Total
----------- --------- --------- -----------
Cash construction expenditures $ 105,979 $ 132,354 $ 116,131 $ 354,464
=========== ========= ========= ===========
Net cash flow from operating activities $ (213,579) $ 112,010 $ 122,329 $ 20,760
Less common & preferred cash dividends 89,901 84,899 81,746 256,546
----------- --------- --------- -----------
Internally generated cash (303,480) 27,111 40,583 (235,786)
Add equity contribution from parent 104,948 14,000 22,000 140,948
----------- --------- --------- -----------
Total cash available $ (198,532) $ 41,111 $ 62,583 $ (94,838)
=========== ========= ========= ===========
Internally generated cash as a percentage of
cash construction expenditures Not Applicable 20% 35% Not Applicable
Total cash generated (used) as a percentage of
cash construction expenditures Not Applicable 31% 54% Not Applicable
- ---------------------------------------------------------------------------------------------------------------------------------
SPPC's estimated cash construction expenditures for 2002 through 2006 are
$556 million. SPPC estimates that 29% of its 2002 cash expenditures
(approximately $40 million) will be provided by the issuance of short-term debt
and parent contributions. In 2002, SPPC expects to pay all of its net income in
dividends to SPR and to receive $60 million of capital contribution from SPR.
Cash provided by internally generated funds during 2002 assumes full
recovery of deferred energy over three years; and assumes general rate increases
approved as filed and effective mid-year. To the extent that the PUCN finds that
any of SPPC's deferred energy costs resulted from imprudent purchases, the PUCN
will not permit that amount to be recovered through higher rates, and an
equivalent amount of SPPC's deferred energy cost asset will be required to be
written off. A material write-off of deferred energy costs would have a material
adverse affect on the future results of operations of SPPC and could cause
SPPC's securities to be downgraded by the rating agencies and make it
significantly more difficult to finance operations, and buy fuel and purchased
power from third parties. Also see Construction Expenditures and Financing (SPR
Consolidated) earlier.
Contractual Obligations
The table below provides SPPC's contractual obligations, not including
estimated construction expenditures described above, as of December 31, 2001,
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):
65
Payments Due By Period
2002 2003 2004 2005 2006 Thereafter Total
---------------------------------------------------------------------------------------------------------
Long-Term Debt (1) $ 49,130 $ 20,632 $ 2,621 $ 2,622 $ 52,629 $ 844,566 $ 972,200
Purchased Power 301,558 135,791 41,723 27,306 28,450 63,353 598,181
Coal and Natural Gas 179,710 70,534 65,702 65,628 63,235 352,423 797,232
Operating Leases 8,612 7,337 6,724 6,217 6,212 61,376 96,478
------------- ----------- ------------ -------------- ------------- -------------- ------------
Total Contractual
Cash Obligations $539,010 $ 234,294 $ 116,770 $ 101,773 $ 150,526 $ 1,321,718 $ 2,464,091
============= =========== ============ ============== ============= ============== ============
(1) Includes short-term debt of $46,500.
Capital Structure
As of December 31, 2001, SPPC had short-term debt outstanding of $46.5
million comprised entirely of commercial paper.
On November 29, 2001, SPPC put into place a $150 million unsecured
revolving credit facility replacing an existing $250 million credit facility,
which may be used for working capital and general corporate purposes, including
commercial paper backup. This new credit facility requires SPPC to issue general
and refunding mortgage bonds to secure this credit facility in the event of a
decline in SPPC's senior unsecured debt rating. This facility will expire on
November 28, 2002.
SPPC's actual capital structure at December 31, 2001, and 2000 was as
follows (dollars in thousands):
2001 2000
---------------------- -------------------------
Short-Term Debt (1) $ 49,130 3% $ 328,578 20%
Long-Term Debt 923,070 54% 605,816 37%
Preferred Stock 50,000 3% 50,000 3%
Preferred Trust Securities - - 48,500 3%
Common Equity 692,654 40% 604,795 37%
------------- -------- --------------- ---------
TOTAL $1,714,854 100% $ 1,637,689 100%
============= ======== =============== =========
(1) Including current maturities of long-term debt.
PURCHASED POWER PROCUREMENT (NPC and SPPC)
Traditionally, the Utilities obtained purchased power through annual
and monthly Requests for Proposals ("RFPs") to electric suppliers. Over the past
few years, structural and competitive changes in the energy markets have
decreased the responsiveness of potential suppliers to the Utilities' RFPs. As a
result of the market conditions in late 1999, the Utilities modified their
procurement practices to rely less on the formal RFP process and more on the
broker market. Brokers connect buyers and sellers in order to obtain optimal
pricing for both sides. In October 1999, the Utilities established and utilized
a timed procurement strategy in order to obtain a targeted percentage of their
calculated purchased power requirement for procurement in the forward markets
each month, following an overall trend of procuring power closer to the time of
delivery. The timed procurement strategy was implemented at a time when the PUCN
had ordered the Utilities to sell their generation plants in anticipation of
retail competition and when it was still unclear what role the Utilities would
play as a provider of last resort.
As the price of purchased power escalated in the late Spring of 2000
and serious concerns developed regarding the availability of purchased power in
California and throughout the western United States, the
66
Utilities began accelerating and extending their timed procurement strategies to
fill summer peak requirements for 2001 and 2002. In an effort to mitigate the
higher costs for 2001 energy procurement at the height of the crisis and to
insure availability of electricity to the Utilities' customers, the Utilities
entered into forward agreements covering 2001 and 2002 in order to take
advantage of the then lower pricing for 2002 purchases. The Utilities are
currently working with major regional suppliers seeking bids to blend some of
their existing forward contract prices (for deliveries in 2002 through 2005) to
smooth out recent spikes in forward contract prices and to reduce overall
purchased power costs for deliveries in 2002. At this time the Utilities cannot
predict the likelihood of success of these efforts.
The Utilities continued to use the monthly RFP process in 2001, with
the exception of the months of March through September for NPC. During the
months of March through September, NPC had already secured purchased power
resources such that it could rely on the spot market for its remaining power
requirements.
In NPC's Refiled 2000 Resource Plan (PUCN Docket No. 01-7016) and
SPPC's 2001 Resource Plan (PUCN Docket No. 01-7004), the Utilities set forth
their base long-term procurement strategy which has since been modified to
include obtaining up to 300 MW for NPC and 250 MW for SPPC of firm, baseload
energy (seven days a week, twenty four hours a day) beginning January 1, 2004,
with up to 500 MW of intermediate and peaking power purchases for delivery in
the second and third quarter of each year.
The Utilities' purchased power procurement strategy involves an
analysis of the Utilities' energy requirements to meet the needs of their retail
and FERC jurisdictional loads. Net energy requirements are determined by
subtracting already secured resources, including power plant generation,
cogeneration facilities and previously purchased power contracts, from the
Utilities' forecasted energy requirements. Once the net energy requirements are
established, future energy prices are analyzed, using the forward market as the
best predictor of future prices.
The net energy requirements and applicable pricing data are presented
to the Utilities' Risk Management Committee ("RMC") which analyzes these
requirements, reviews alternative purchasing strategies and provides guidance on
the timing and quantity of purchases. See Item 7A, Quantitative and Qualitative
Disclosures About Market Risk for additional discussion regarding the RMC's role
and the application of risk management policies. The RMC regularly reviews
updated transaction information, available secured energy resources and power
requirements in order to determine secured resources requirements as well as
total power requirements.
Short Term Power Procurement Strategy
The Utilities' short term power procurement 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. After
connecting generation units to the system, the Utilities dispatch the generation
output based on the comparative economics of generation versus spot-market
purchase opportunities and determine the amount of excess capacity, which is
then sold on the wholesale market, or the amount of deficiency capacity, which
must be procured on an hourly basis.
The day-ahead resource coordination begins with an analysis of
projected loads and existing resources. Firm forward take-or-pay contracts are
scheduled and counted towards meeting the capacity needs of the day being
pre-scheduled. Any deficiency in the projected operating reserve for the next
day, after consideration of available internal generation resources is met by
additional firm purchased power resources. The day-of resource coordination
involves minimizing system production costs each hour by either changing the
generation output or buying needed power/selling excess power in the wholesale
market. Any sale of excess power priced above the incremental cost of producing
such power reduces the net production cost of operating the electrical
67
system and thereby benefits the end use customer. The Utilities endeavor to
reduce the electrical systems' net production cost by selling the available
excess power resources.
Real-time resource coordination requires an hourly determination of
whether to run generation or purchase power in order to achieve the lowest
production costs by calculating the projected incremental or decremental cost of
generation required to meet the forecast load in comparison to obtaining power
in the wholesale power market. In the event that committed generators suffer a
forced outage that is expected to last through the remaining monthly period, the
operating cost of the next available generation resource is compared to purchase
power options to determine the lowest cost option.
Term Power Procurement Strategy
The majority of the Utilities' purchased power resources are secured
through term transactions (transactions of greater than one month). To
coordinate fuel and purchase power resources, the Utilities analyze their
existing portfolios of fuel and purchased power and the projected electrical
system loads for the period under consideration. Existing contracts for natural
gas and purchased power are compared to the projected load profile to determine
if there are adequate resources to cover the peak loads plus reasonable
reserves.
If monthly resources are insufficient to cover the average daily peak
plus 7%, the cost of generating additional electrical energy is compared to the
available purchase power cost to determine the lowest cost option for securing
additional power resources. If the monthly resources exceed the requirements of
the average daily peak plus 7%, the Utilities analyze whether it is more
cost-efficient to sell off power and power resources or to keep the excess power
to cover generation contingencies and deal with the excesses on a daily or
hourly basis.
Hedging Transactions
Over the last two years the Utilities have used hedges to reduce price
and commodity risk for future purchases by executing contracts at so-called
"liquid" trading points. A liquid trading point is a hub where significant
volumes of energy are freely purchased and sold amongst many parties at a heavy
volume so that one particular transaction has no discernable effect on the
market price of energy at that trading point. The hedged purchases are either
delivered to the Utilities' service territories to service their customers or,
if the hedged purchase is not needed to fulfill power requirements, resold in
the liquid market depending upon the size of the load, the status of internal
generation, and the market price at time of delivery.
A typical hedge transaction involves the purchase or sale of power at
one of the major trading hubs where prices are highly correlated to the ultimate
point of delivery. The following is an illustration of a typical hedging
transaction for NPC. NPC's main point of interconnection with the Western System
Coordinating Council grid is at Mead Substation, Nevada. If NPC seeks to
purchase 25 MW of power for delivery on a specified future date, NPC can
purchase energy from other major trading hubs that are highly correlated to
Mead, such as Palo Verde, Arizona, thereby assuring the availability of 25 MW
electricity on that date to meet anticipated loads. By purchasing power at Palo
Verde, NPC is also protected from the risk of market participants knowing that
NPC must make a purchase and the resultant increase in prices at NPC's primary
point of delivery. Once it makes the purchase at Palo Verde, NPC will
continually monitor whether other power might be available at a lower total
cost, including the cost of transmitting the electricity to NPC's system. If NPC
finds an opportunity to purchase the same amount of power at delivery hubs
closer to Mead, such as Pinnacle Peak Substation in Arizona, for a lower total
cost than taking delivery of the original purchase at Palo Verde, NPC will sell
its 25 MW position at Palo Verde and purchase the 25 MW position for delivery at
Pinnacle Peak. Shortly before the date of delivery, NPC may have an opportunity
to procure yet another source of power that will deliver 25 MW more cheaply, on
a total cost basis, directly to Mead Substation. NPC would
68
therefore sell the 25 MW position at Pinnacle Peak and purchase the 25 MW
position for delivery at Mead Substation.
In the above example, NPC will record a total of 75 MW of purchased
power expense, 50 MW of wholesale power sales and 25 MW of retail sales, all of
which are related to meeting the same 25 MW load requirement. This series of
transactions is designed to acquire power at the lowest feasible total cost
while at the same time ensuring that the basic commodity will be available on
the date needed. At no time are the Utilities trading power on a speculative
basis. Any savings in costs achieved by such a series of transactions will lower
the Utility's overall costs for purchased power and therefore reduce the
Utility's deferred energy account balance.
RESULTS OF OPERATIONS - OTHER SUBSIDIARIES
------------------------------------------
Tuscarora Gas Pipeline Company
TGPC, a wholly owned subsidiary of SPR, contributed $2.6 million in net
income for the twelve months ended December 31, 2001, and $2.1 million in net
income for the twelve months ended December 31, 2000. The Consolidated
Statements of Income of Sierra Pacific Resources for the year ended December 31,
1999, include the operating results of TGPC for the five month period ended
December 31, 1999, based on a merger date of August 1, 1999, for accounting
purposes. TGPC contributed $711,000 in net income for the five months ended
December 31, 1999, and $1.8 million in net income for the twelve months ended
December 31, 1999.
Sierra Pacific Communications
SPC, a wholly owned subsidiary of SPR, incurred a net loss of ($2.9)
million for the twelve months ended December 31, 2001, and a net loss of
($989,000) for the twelve months ended December 31, 2000. The Consolidated
Statements of Income of Sierra Pacific Resources for the year ended December 31,
1999, include the operating results of SPC, for the five month period ended
December 31, 1999, based on a merger date of August 1, 1999, for accounting
purposes. SPC incurred a net loss of ($62,000) for the five months ended
December 31, 1999, and a net loss of ($75,000) for the twelve months ended
December 31, 1999.
e.three
e.three, a wholly owned subsidiary of SPR, contributed $666,000 of net
income for the twelve months ended December 31, 2001, and $338,000 of net income
for the twelve months ended December 31, 2000. The Consolidated Statements of
Income of Sierra Pacific Resources for the year ended December 31, 1999, include
the operating results of e.three, for the five month period ended December 31,
1999, based on a merger date of August 1, 1999, for accounting purposes. e.
three incurred a net loss of ($381,000) for the five months ended December 31,
1999, and a net loss of ($788,000) for the twelve months ended December 31,
1999.
Sierra Pacific Energy Company
SPE, a wholly owned subsidiary of SPR, incurred a net loss of
($335,000) for the twelve months ended December 31, 2001, and a net loss of
($4.5) million for the twelve months ended December 31, 2000. The Consolidated
Statements of Income of Sierra Pacific Resources for the year ended December 31,
1999, include the operating results of SPE for the five month period ended
December 31, 1999, based on a merger date of August 1, 1999, for accounting
purposes. SPE incurred a net loss of ($2.2) million for the five months ended
December 31, 1999, and a net loss of ($3.6) million for the twelve months ended
December 31, 1999.
69
Lands of Sierra
LOS, a wholly owned subsidiary of SPR, incurred a net loss of
($281,000) for the twelve months ended December 31, 2001, and a net loss of
($191,000) for the twelve months ended December 31, 2000. The Consolidated
Statements of Income of Sierra Pacific Resources for the year ended December 31,
1999, include the operating results of LOS for the five month period ended
December 31, 1999, based on a merger date of August 1, 1999, for accounting
purposes. LOS contributed net income of $816,000 for the five months ended
December 31, 1999, and net income of $810,000 for the twelve months ended
December 31, 1999.
Nevada Electric Investment Company
Nevada Electric Investment Company (NEICO), a wholly owned subsidiary
of SPR, contributed net income of $101,000 for the twelve months ended December
31, 2001, and net income of $384,000 for the twelve months ended December 31,
2000. Prior to 2000, NEICO was a wholly owned subsidiary of NPC. Accordingly,
NEICO's operating results for the twelve months ended December 31, 1999 (a net
loss of $594,000), are included in NPC's operating results for that period.
Sierra Pacific Resources (Holding Company)
The holding company operating results included approximately $55.8
million, $44.5 million, and $11.5 million of interest costs for 2001, 2000, and
1999, respectively, that resulted primarily from the merger financing. For
additional merger information, see Note 2 to the Consolidated Financial
Statements included in this report.
REGULATION AND RATE PROCEEDINGS
-------------------------------
Nevada Matters (NPC and SPPC)
- -----------------------------
The Utilities are subject to the jurisdiction of the PUCN and, in the
case of SPPC, the California Public Utility Commission (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 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 Health District (CCHD) 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.
70
Nevada Legislation
- ------------------
On April 18, 2001, the Governor of Nevada signed into law AB 369. The
provisions of AB 369 include a moratorium on the sale of generation assets by
electric utilities, the repeal of electric industry restructuring, and a
reinstatement of deferred energy accounting for fuel and purchased power costs
incurred by electric utilities. The stated purposes of this emergency
legislation were, among others, to control volatility in the price of
electricity in the retail market in Nevada, and to ensure that the Utilities
have the necessary financial resources to provide adequate and reliable electric
service under present market conditions. To achieve these purposes, AB 369
allows the Utilities to recover in future periods their current costs for
wholesale power and fuel, which have risen dramatically over the past year.
Deferred energy accounting will have the effect of delaying additional rate
increases to consumers until the second quarter of 2002 while, at the same time,
providing a method for the Utilities to recover their increased costs for fuel
and purchased power. Set forth below is a summary of key provisions of AB 369.
Generation Divestiture Moratorium
AB 369 prohibits all divestiture of generation assets by electric
utilities until July 2003. After January 1, 2003, NPC or SPPC may seek PUCN
permission to sell one or more generation assets with the sale to be effective
on or after July 1, 2003. The PUCN may approve the request to divest only if it
finds the transaction to be in the public interest. The PUCN may base its
approval of the request upon such terms, conditions, or modifications as it
deems appropriate.
AB 369 directs the PUCN to take all steps necessary to obtain federal
approval for the prohibition on divestiture and to vacate any of its own orders
that had previously approved generation divestiture transactions.
Deferred Energy Accounting
AB 369 required the Utilities to use deferred energy accounting for
their respective electric operations beginning on March 1, 2001. The intent of
deferred energy accounting is to ease the effect of fluctuations in the cost of
purchased power and fuel. See Note 3 to the Financial Statements for a
discussion of the deferred energy accounting provisions of AB 369.
Transition of Rates to Deferred Energy Accounting
All rates in effect on April 1, 2001, including the cumulative
increases under the Global Settlement and the CEP Riders, remain in effect until
the PUCN issues final orders on future general and initial deferred energy rate
applications. (See "Required Filings," below). No further applications can be
made for the Fuel and Purchased Power (F&PP) riders that were part of the July
2000 Global Settlement described in SPR's Annual Report on Form 10-K for the
year ended December 31, 2000.
The Utilities are not permitted to recover any shortfall incurred
before March 1, 2001, resulting from the difference between actual fuel and
purchased power costs and the rates permitted by the Global Settlement. Although
the F&PP riders were in effect during this period, the riders were based on
trailing 12-month average costs and were subject to caps and, therefore, did not
allow the Utilities full recovery for fuel and purchased power costs due to the
rapid rise in energy prices.
AB 369 prohibits the PUCN from taking any further action on the CEP,
and provides that, except for the CEP Rider rate increases put in effect on
April 1, 2001, the CEP will be deemed to have been withdrawn by the Utilities.
Additionally, approximately $20 million of revenue collected by the Utilities
based on the CEP before
71
April 1, 2001 was credited to the deferred energy accounts, which caused the
accounts to start in an over-collected position.
Required Filings
The Utilities have both filed a general rate application and a deferred
energy application on the dates listed below:
General Rate Case Deferred Energy Filing
----------------- ----------------------
File Date Effective Date File Date Effective Date
Nevada Power Company Oct. 1, 2001 April 1, 2002 Dec. 1, 2001 April 1, 2002
Sierra Pacific Power Company Dec. 1, 2001 June 1, 2002 Feb. 1, 2002 June 1, 2002
In connection with clearing the Utilities' deferred energy accounts,
the PUCN must investigate and determine whether the Utilities' rates that went
into effect on March 1, 2001, pursuant to the CEP, are just and reasonable and
reflect prudent business practices. The rates in effect on April 1, 2001, remain
in effect until the PUCN issues final orders on the general and initial deferred
energy rate applications referred to above. The PUCN is prohibited from
adjusting rates during this time period unless an adjustment is absolutely
necessary to avoid a finding that the rates are confiscatory and, therefore, in
violation of the United States or Nevada Constitutions. If adjustments are
necessary, they may only be made to the extent necessary to avoid an
unconstitutional result.
After the initial general rate applications described above, each
Utility will be required to file future general rate applications at least every
24 months.
See "Nevada Power Company General Rate Case," later, for a discussion
of NPC's general rate application filed on October 1, 2001 and "Nevada Power
Company Deferred Energy Case," later, for a discussion of NPC's deferred rate
application filed on November 30, 2001.
See "Sierra Pacific Power Company General Rate Case," later, for a
discussion of SPPC's general rate application filed on November 30, 2001 and
"Sierra Pacific Power Company Deferred Energy Case," later, for a discussion of
SPPC's deferred rate application filed on February 1, 2002.
Restrictions on Mergers and Acquisitions
AB 369 imposes certain restrictions on mergers and acquisitions
involving Nevada electric utilities. In particular, the PUCN may not approve a
merger or acquisition involving an electric utility unless the utility complies
with the generation divestiture provisions of AB 369.
In addition, AB 369 includes provisions that would have significantly
affected the required regulatory approvals for the proposed acquisition of PGE
from Enron. On April 26, 2001, Enron and SPR terminated, by mutual agreement,
the proposed purchase and sale of PGE.
AB 369 also provides that if an electric utility holding company
acquires an interest in an out-of-state public utility prior to July 1, 2003,
each electric utility in which the holding company holds a controlling interest
shall not be entitled to the benefit of deferred energy accounting. Thus, in the
event that SPR acquires an out-of-state public utility, NPC and SPPC would lose
the ability to utilize deferred energy accounting.
72
Repeal of Electric Industry Restructuring
AB 369 repeals all statutes authorizing retail competition in Nevada's
electric utility industry and voids any license issued to an alternative seller
in connection with retail electric competition.
Other Legislation
SB 372, which increased renewable energy portfolio requirements, was
enacted in the 2001 Nevada legislative session. Renewable resources include
biomass, wind, solar, and geothermal projects. In 2003, the Utilities will be
required to purchase five percent of their energy from renewable resources.
These requirements increase to 15% by 2013. Prior law capped renewable energy
requirements at one percent. Currently, SPPC obtains approximately nine percent
of its energy from renewable resources, while NPC obtains less than one percent
from renewables. SB 372 requires the PUCN to establish standards for renewable
energy contracts, including prices and other terms and conditions. If sufficient
renewable energy contracts that meet PUCN standards are not available, the
Utilities will not be required to meet the portfolio requirements. All renewable
energy contracts meeting PUCN standards will be recoverable in the deferred
energy accounts.
The 2001 Nevada legislature passed another key piece of legislation for
the Nevada energy industry, AB 661. AB 661 allows commercial and governmental
customers with an average demand greater than 1 MW to select new energy
suppliers. The Utilities would continue to provide transmission, distribution,
metering and billing services to such customers. AB 661 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 the Utilities, remaining
customers or the utility cannot be negatively impacted by the departure, and the
departing customers must pay any deferred energy balances. The PUCN has adopted
regulations prescribing the criteria that will be used to determine if there
will be negative impacts to remaining customers or the utility. Certain limits
are placed upon the departure of NPC customers until 2003; most significantly,
the amount of load departing is limited to approximately 1100 MW in peak
conditions. AB 661 permits customers to file applications with the PUCN
beginning in the fourth quarter of 2001. Customers must provide 180-day notice
to the Utilities and could begin to receive service from new suppliers by
mid-2002. On January 10, 2002, an approximately 130 MW SPPC customer submitted
an application to the PUCN under AB 661. The customer, SPPC, and PUCN staff are
negotiating a stipulation regarding settlement of the terms and conditions under
which this customer will be permitted to procure energy from an alternative
source other than SPPC. The terms and conditions of the stipulation are expected
to comply with the provisions of AB 661 in that SPPC and its remaining customers
will not be negatively impacted by the customer's departure. A hearing on the
stipulation has been set for March 20, 2002.
AB 661 also contains new electric and gas energy surcharges for
low-income assistance and weatherization programs. These surcharges are
recoverable directly from customers as separate line items on their bills with
the Utilities remitting collected surcharges to the PUCN. Various state agencies
will administer the disposition of the funds.
Nevada Power Company General Rate Case (NPC)
On October 1, 2001, NPC filed an application with the PUCN seeking an
electric general rate increase. This application was mandated by AB 369, which
was enacted by the Nevada legislature in April 2001. On December 21, 2001, NPC
filed a Certification to its general rate filing updating costs and revenues
pursuant to Nevada regulations. In the certification filing, NPC requested an
increase in its general rates charged to all classes of electric customers
designed to produce an increase in annual electric revenues of $22.7 million,
which is an overall 1.7% rate increase. The application also seeks a return on
common equity ("ROE") for Nevada Power's total electric operations of 12.25% (a
reduction from NPC's last-authorized ROE for bundled electric
73
operations of 12.50%) and an overall rate of return ("ROR") of 9.30% (a
reduction from NPC's last-authorized ROR for bundled electric operations of
10.02%). Public hearings on NPC's general rate case began on February 4, 2002.
Various parties have intervened in NPC's general rate case including the Staff
of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney
General's office, MGM/Mirage, and the Nevada Coalition Of Commercial Energy
Consumers. The reduction of NPC's revenue requirements proposed by the
intervenors ranges from $50 million to $107 million.
Nevada Power Company Deferred Energy Case (NPC)
On November 30, 2001, NPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 through September 30, 2001. This application was mandated by AB
369, which was enacted by the Nevada Legislature in April 2001. The application
seeks to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to
clear accumulated purchased fuel and power costs of $922 million and spread the
cost recovery over a not more than three-year period. It also seeks to
recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased
fuel and power costs. The total rate increase resulting from the DEAA would
amount to 21%. NPC has proposed an alternate plan in which full recovery of the
deferred balance would be amortized over a period greater than three years, but
not to exceed six years. Public hearings began March 4, 2002. Various parties
have intervened in NPC's deferred energy rate case including the Staff of the
PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's
office, MGM/Mirage, the Southern Nevada Water Authority, the Nevada Energy
Buyers Group, and the Nevada Coalition Of Commercial Energy Consumers. The
disallowance of NPC's deferred energy balance that is proposed by the
intervenors ranges from $85 million to $980 million. The disallowance of a
significant amount of NPC's deferred energy costs could result in NPC becoming
insolvent. Some intervenors have argued that disallowance of NPC's deferred
energy costs would be in the best interests of ratepayers based on speculation
that some of the deferred energy costs could be avoided under bankruptcy laws if
NPC were to become subject to bankruptcy proceedings.
Sierra Pacific Power Company General Rate Case (SPPC)
On November 30, 2001, SPPC filed an application with the PUCN seeking
an electric general rate increase. This application was mandated by AB 369,
which was enacted by the Nevada Legislature in April 2001. On February 28, 2002,
SPPC filed a certification to its general rate filing, updating costs and
revenues pursuant to Nevada regulations. In the certification filing, SPPC
requested an increase in its general rates charged to all classes of electric
customers, which were designed to produce an increase in annual electric
revenues of $15.9 million representing an overall 2.4% rate increase. The
application also seeks an ROE for SPPC's total electric operations of 12.25% (an
increase from SPPC's last authorized ROE for bundled electric operations of
12.0%) and an overall ROR of 9.42% (a reduction from SPPC's last authorized ROR
for bundled electric operations of 10%). Public hearings for SPPC's general rate
case are scheduled to begin on April 8, 2002. Various parties have intervened in
SPPC's general rate case including the Staff of the PUCN, the Bureau of Consumer
Protection from the Nevada Attorney General's office, and Barrick Goldstrike
Mines, among others. Intervenor testimony will not be filed until March 22,
2002.
Sierra Pacific Power Company Deferred Energy Case (SPPC)
On February 1, 2002, SPPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 and November 30, 2001. This application was mandated by AB 369.
The application seeks to establish a DEAA rate to clear accumulated purchased
fuel and power costs of $205 million and spread the cost recovery over a not
more than three-year period. It also seeks to recalculate the Base Tariff Energy
Rate to reflect anticipated ongoing purchased fuel and power costs. The total
rate increase resulting from the DEAA would amount to 9.8%. SPPC has proposed an
alternate plan in which full recovery of the deferred balance would be amortized
over a period greater than three years, but not to exceed six years. Public
hearings are scheduled to begin in April 2002. Various parties have intervened
in SPPC's deferred energy rate case including the Staff of the PUCN, the Bureau
of Consumer Protection from the Nevada Attorney General's office, and Barrick
Goldstrike Mines, among others. Intervenor testimony will not be filed until
April 22, 2002. The disallowance of a significant amount of SPPC's deferred
energy costs could result in SPPC becoming insolvent.
74
Resource Plans (SPPC, NPC)
On July 2, 2001, SPPC filed its electric resource plan for the period
of 2001-2020. On July 9, 2001, NPC filed its amended electric resource plan for
the period of 2000-2019. The plans include scenarios to meet the electric needs
of customers while sustaining reliable electric systems. The integrated resource
plans evaluate resources to be used to meet forecasted loads. Resource options
considered include new transmission lines to access energy markets, construction
of generation facilities, power purchases from IPP's under short- and long-term
agreements, and conservation programs. On October 18, 2001, the PUCN approved
NPC's amended resource plan. On August 2, 2001, a pre-hearing conference was
held on SPPC's resource plan and procedural orders were established. Public
hearings on SPPC's plan were held in late October, and on November 1, 2001, the
PUCN issued an order approving and adopting SPPC's plan.
PUCN Rulemaking for Assembly Bill 661 (SPPC, NPC)
The PUCN opened an investigatory and rulemaking docket to implement the
provisions of AB 661. The PUCN has scheduled a workshop to receive comments
regarding proposed regulations. These regulations concern eligible customers
purchasing new electric resources from suppliers other than SPPC or NPC. A
public hearing regarding the regulation was held on October 30, 2001. On
November 26, 2001, the PUCN approved the regulations.
Optional Conservation Service (NPC, SPPC)
On April 19, 2001, the PUCN approved new NPC and SPPC electric rates
for Optional Conservation Service (Schedule OC). Schedule OC allows the
Utilities to request customers with demand greater than 1 MW to voluntarily
curtail their load when there is an economic or system need for capacity and
energy. Customers who curtail load will receive a billing credit.
Parallel Generation Tariffs (NPC, SPPC)
On May 11, 2001, the Utilities filed with the PUCN revisions to
existing tariffs that will allow customers to interconnect standby generators in
parallel with the Utilities' facilities. These changes will allow customers
meeting specific requirements to utilize their standby generators in support of
the Optional Conservation Service tariffs during times of power shortages or
higher prices. On August 3, 2001, the PUCN approved the revisions.
Finance Authority (NPC, SPPC)
On September 20, 2001, the PUCN approved the June 19, 2001 applications
by the Utilities for authority to issue long or short-term debt on either a
secured or unsecured basis in an aggregate amount not to exceed $200 million for
NPC and $100 million for SPPC through the end of 2002. NPC has issued all of its
$200 million of authorized debt. SPPC has not issued any debt under this
authority and has the full amount of the $100 million of authorized debt
available for future issuances. On September 20, 2001, the PUCN also approved
the Utilities' June 19, 2001 applications to amend an order issued by the PUCN
allowing each of the Utilities to issue unsecured short-term promissory notes in
an amount not to exceed $250 million through the period ending December 31,
2001. In the applications, the Utilities requested that the PUCN amend its
previous order to provide the Utilities with the flexibility to issue secured
promissory notes in addition to, or in lieu of, the authorized unsecured
promissory notes.
On October 1, 2001, NPC and SPPC each filed an application with the
PUCN requesting authority to issue secured or unsecured promissory notes in
aggregate amounts not to exceed $250 million through December 31, 2004. On
October 9, 2001, the Utilities filed amended applications reducing the time
period to
75
December 31, 2003. On November 29, 2001, the PUCN issued a compliance order
approving the requests. Currently, NPC has $50 million and SPPC has $100 million
of short-term debt authority remaining from these PUCN authorizations.
Natural Gas Rate Increase (SPPC)
On June 29, 2001, SPPC filed with the PUCN a Purchase Gas Adjustment
(PGA) seeking recovery of $41.4 million in accumulated, unrecovered purchased
gas expenses, and an increase in the going-forward rate to $.71 per therm.
Public hearings were held on October 22 and 23, 2001. On November 5, 2001, the
PUCN granted SPPC's application and approved recovery of the entire $41.4
million accumulated deferred balance over a three-year period and an increase in
the going-forward rate to $.6648 per therm. Any over or under-recovery of future
energy costs will be the subject of a future PGA application. SPPC will file its
next PGA on July 1, 2002.
SPR and NPC Merger (NPC and SPPC)
The merger between SPR and NPC was finalized on July 28, 1999. As part
of the conditions for the merger, the Utilities were each required to divest all
generation assets and file a general rate case unbundling costs. In May 1999,
the Nevada Legislature passed SB 438, which modified the electric restructuring
statutes. The Utilities filed general rate cases, unbundling costs and filed
distribution rates for an unregulated market. However, in April of 2001 the
Nevada Legislature passed AB 369, discussed earlier, which repealed the
condition that the Utilities divest their generation assets and placed a
moratorium on the sale of any generation assets until July 2003. AB 369 also
repealed electric restructuring (deregulation).
FERC Matters (NPC and SPPC)
- ---------------------------
Price Mitigation Plan
On June 19, 2001, the FERC adopted a price mitigation plan applicable
to spot market wholesale power sales in California and throughout the western
United States during the period June 20, 2001 through September 30, 2002. The
price mitigation plan establishes a mechanism with which to determine the
maximum amount that may be charged for power sold during this period. The intent
of the mitigation plan is to simulate the price that might be charged for
electricity sold under competitive market conditions. Sellers that do not wish
to establish rates on the basis of this price mitigation plan may propose
cost-of-service rates covering all of their generating units in the WSCC for the
duration of the mitigation plan. Although the Utilities are not able to predict
at this time the long-term effect that the FERC price mitigation plan and other
market developments may have on their results of operations, management believes
that, under certain market conditions, the FERC plan adversely affects the
availability of spot market power to the Utilities and reduces the price at
which the Utilities can sell power on the wholesale market. Another potential
result from these price mitigation measures could be the delay and/or
cancellation of proposed power plants throughout the western United States. If
these results occur, the long-term supply of energy could be reduced. Numerous
parties, including NPC and several northwest utilities, appealed the June 19 and
July 25, 2001 orders from the FERC to the District of Columbia Court of Appeals
on the basis that the price caps are unfair to electric customers who reside
outside of California. In a report to Congress on January 31, 2002, the FERC
said the price mitigation plan had little if any influence on prices at which
Western utilities were able to resell power. SPR is not persuaded by the FERC's
report and continues to believe that the FERC's price caps have negatively
impacted electric customers outside California. The parties to the appeal await
action by the Court.
76
Regional Transmission Organization and Independent Transmission Company
NPC and SPPC are members of the utility groups that are forming a
proposed regional transmission organization (RTO West) and a proposed
independent transmission company (TransConnect).
In October 2000, RTO West submitted to the FERC a compliance filing and
supplemental material, which provided details of the formation of the RTO. RTO
West, as proposed, would be a non-profit independent system operator of the
regional transmission grid, governed by an independent board of directors. This
filing was made in compliance with FERC Order 2000, which required all
investor-owned utilities in the United States who own interstate transmission to
file a proposal to participate in an RTO or an explanation of efforts and plans
to participate in an RTO. Also in October 2000, TransConnect submitted to the
FERC a proposal to form a for-profit Independent Transmission Company which
would become a member of RTO West.
On April 25, 2001, FERC gave preliminary approval for both RTO West and
TransConnect. On November 13, 2001, TransConnect submitted a filing to FERC
asking for preliminary approval of its proposed transmission rate structure,
modified governance proposal, and transmission planning and expansion protocol.
On December 1, 2001, RTO West submitted a status report on its development
efforts to FERC in compliance with FERC's April 2001 order. Both organizations
remain subject to approvals from state regulators and the board of directors of
each member company.
The current filing utility members of RTO West are NPC, SPPC, Avista
Corporation, British Columbia Hydro & Power Authority, Bonneville Power
Administration (BPA), Idaho Power Company, The Montana Power Company,
PacifiCorp, Portland General Electric, and Puget Sound Energy, Inc. The current
filing utility members of TransConnect are NPC, SPPC, Avista Corporation, and
Portland General Electric.
Wholesale Sales Tariffs
On March 13, 2001, the Utilities each filed an application for an order
approving market-based rates. The market-based authority would apply to sales of
electric energy and capacity outside of the Utilities' control areas. On May 11,
2001, SPPC and NPC received approval for market-based rates subject to a
compliance order. SPPC's and NPC's compliance filing was accepted on August 10,
2001.
Alturas Intertie
Certain Northern California public power groups have challenged SPPC's
filing with the FERC of the interconnection and operating agreements related to
the Alturas Intertie in December 1998 and January 1999. The California groups
alleged that the potential reduction in imports into California constitutes an
impairment of reliability and therefore seek to force reductions in use of the
Alturas Intertie during peak periods. SPPC (supported by Bonneville Power
Administration and PacifiCorp) has filed testimony before the FERC that the
Alturas Intertie does not adversely affect reliability and that, under the
FERC's Order No. 888, customers in Nevada are entitled to compete with customers
in California for transmission capacity in the Pacific Northwest on a
first-come, first-served basis. The FERC staff has agreed with SPPC's position
on this matter. The matter was tried to an Administrative Law Judge (ALJ) in
April and May 2000. In 2001, the ALJ agreed with SPPC's position, but imposed a
limitation on additional transfer capacity created by future upgrades to the
system. The ALJ stated allocation of additional transfer capacity would require
agreement among the parties. Both sides have appealed this decision to the full
FERC.
77
California Matters (SPPC)
- -------------------------
Rate Stabilization Plan
SPPC serves approximately 44,500 customers in California. On June 29,
2001, SPPC filed with the CPUC a Rate Stabilization Plan, which includes two
phases. Phase One, which was also filed June 29, 2001, is an emergency electric
rate increase of $10.2 million annually or 26%. If granted, the typical
residential monthly electric bill for a customer using 650 kilowatt-hours would
increase from approximately $47.12 to $60.12. On August 14, 2001, a pre-hearing
conference was held, and a procedural order was established. On September 27,
2001, the Administrative Law Judge issued an order stating that no interim or
emergency relief could be granted until the end of the "rate freeze" period
mandated by the California restructuring law for recovery of stranded costs. In
accordance with the judge's request, on October 26, 2001, SPPC filed an
amendment to its application declaring the rate freeze period to be over.
Phase Two, which is scheduled to be filed with the CPUC in April 2002,
will be a general rate case to recover costs for expenses other than fuel and
purchased power. SPPC will also ask the CPUC to reinstate the Energy Cost
Adjustment Clause, which would allow SPPC to file for periodic rate adjustments
to reflect its actual costs for fuel and purchased power. Phase Two will also
include a proposal pertaining to the termination of the 10% rate reduction
mandated by AB 1890. On December 5 and 11, 2001 hearings on Phase One were held
and on January 11, 2002, opening briefs were filed. Reply briefs were filed on
January 25, 2002. A proposed draft decision is expected by the end of March
2002. SPPC will file Phase Two on April 1, 2002.
Distribution Performance-based Rate-making
Hearings on SPPC's distribution performance -based rate-making (PBR)
proposal were held on April 2, 2001. An outline of the settlement reached by
SPPC, the CPUC Office of Ratepayer Advocates, and The Utility Reform Network
resolving all issues was presented during the hearing. On May 11, 2001, a formal
joint settlement was submitted to the Administrative Law Judge. To date there
has been no formal action on the filed joint settlement. On December 11, 2001,
the Commission approved an order dismissing the application because of the
pending emergency rate increase request and SPPC's plans to file a GRC. This
decision approved parts of the joint settlement agreement and the record of the
proceeding will be available for use in future proceedings before the
Commission.
California Assembly Bill 6X
On January 18, 2001, the California Legislature passed Assembly Bill
(AB) 6X. AB 6X modified Section 377 of California law restricting the sale of
generation assets. AB 6X states that no facility for the generation of
electricity owned by a public utility may be disposed of prior to January 1,
2006. Since SPPC is a public utility serving California customers, the sale of
SPPC's generation assets was halted. The sale of the Mohave Generating Station,
in which NPC has a 14% undivided interest, was also stopped because Southern
California Edison is an operating partner of that facility.
78
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
SPR has evaluated its risk related to financial instruments whose values
are subject to market sensitivity. Such instruments are fixed and variable rate
debt, and preferred trust securities obligations, which were as follows on
December 31, 2001, and 2000. Fair market value was determined using quoted
market price for the same or similar issues or on the current rates offered for
debt of the same remaining maturities.
Long-term debt (dollars in thousands):
Expected Maturity December 31, 2001
Date
---------------------------------------------------------------------------------------------------------
Expected Maturities Amounts Weighted Avg Int Rate * Fair Market Value
---------------------------------------------------------------------------------------------------------
Fixed Rate NPC SPPC SPR Consolidated Consolidated Consolidated
------------------------------------------------------- --------------------- -------------------
2002 $ 15,000 $ 2,630 $ - $ 17,630 7.40%
2003 210,000 20,632 - 230,632 5.97%
2004 130,000 2,621 - 132,621 6.10%
2005 - 2,622 300,000 302,622 8.73%
2006 - 52,629 - 52,629 6.71%
Thereafter 938,835 845,527 345,000 2,129,362 6.87%
------------------------------------------------------- --------------------- -------------------
Total Fixed Rate $1,293,835 $ 926,661 $ 645,000 $ 2,865,496 $ 2,953,374
------------------------------------------------------- --------------------- -------------------
Variable Rate
2002 $ - $ - $ 100,000 $ 100,000 3.04%
2003 140,000 - 200,000 340,000 3.43%
2004 - - - -
2005 - - - -
2006 - - - -
Thereafter 115,000 - - 115,000 1.82%
------------------------------------------------------- --------------------- -------------------
$ 255,000 $ - $ 300,000 $ 555,000 $ 549,400
------------------------------------------------------- --------------------- -------------------
Preferred securities
(fixed rate)
After 2006 $ 188,872 $ - $ - $ 188,872 8.03%
------------------------------------------------------- --------------------- -------------------
$ 188,872 $ - $ - $ 188,872 $ 181,525
------------------------------------------------------- --------------------- -------------------
Total $1,737,707 $ 926,661 $ 945,000 $ 3,609,368 $ 3,684,299
- ----------------------=======================================================-------------------------------===================
79
Expected Maturity December 31, 2000
---------------------------------------------------------------------------------------------------------
Expected Maturities Amounts Weighted Avg Int Rate * Fair Market Value
---------------------------------------------------------------------------------------------------------
Fixed Rate NPC SPPC SPR Consolidated Consolidated
---------------------------------------------------------------------------------------------------------
2001 $ 100 $ 19,620 $ - $ 19,720 5.57%
2002 15,000 2,626 - 17,626 7.40%
2003 - 20,632 - 20,632 5.63%
2004 130,000 2,621 - 132,621 6.20%
2005 - 2,622 300,000 302,622 8.73%
Thereafter 588,942 497,311 - 1,086,253 6.65%
======================================================= ===================== ===================
Total Fixed Rate $ 734,042 $ 545,432 $ 300,000 $ 1,579,474 $ 1,579,221
------------------------------------------------------- --------------------- -------------------
Variable Rate
2001 $ 250,000 $ 200,000 $ - $ 450,000 7.48%
2002 - - 100,000 100,000 7.29%
2003 - - 200,000 200,000 7.24%
2004 - - - -
2005 - - - -
Thereafter 115,000 80,000 - 195,000 4.37%
======================================================= --------------------- ===================
$ 365,000 $ 280,000 $ 300,000 $ 945,000 $ 941,920
------------------------------------------------------- --------------------- -------------------
Peferred securities
(fixed rate)
After 2005 $ 188,872 $ 48,500 $ - $ 237,372 8.15% $ 234,792
======================================================= ===================== ===================
Total $1,287,914 $ 873,932 $ 600,000 $ 2,761,846 $ 2,755,933
- ----------------------=======================================================-------------------------------===================
* Weighted daily average rate for months ended December 31, 2001, and 2000.
COMMODITY PRICE RISK
SPR is 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 Purchased Power Procurement 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.
The Utilities' efforts to manage energy commodity (electricity,
natural gas, coal and oil) price risk are governed by a Board of Directors
approved Energy Risk Management Policy. That policy is augmented by an IT system
to track any commodity price exposure. The Energy Risk Management Policy sets
forth business objectives, organizational structure, performance metrics and
operating requirements. The policy also establishes guidelines for the Risk
Management Committee ("RMC"), which is responsible for providing management
advice and recommendations on energy risk management related issues. The RMC met
periodically throughout 2001.
The Utilities' commodity risk management program establishes a control
framework based on existing commercial practices. The program creates common
predefined risk parameters 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 performance parameters.
The objective of the Utilities' energy risk management program is to
help management exercise informed judgments on risk assessment and management.
Supporting activities are designed:
80
. To provide management with a quantification of the Utilities' cash flow
requirements for fuel and purchased power;
. To provide management with a quantification of the Utilities' cash flow
sensitivity to movements in energy markets;
. To provide management with a quantification of the expected retail rate
impact attributable to expenditures for fuel and purchased power;
. To provide management with estimates of the sensitivity of retail rates to
movements in energy markets;
. To extract market pricing information that can be used in future decisions;
and
. To help to optimize the output from the Utilities' generation assets.
On March 1, 2001, deferred energy accounting procedures were applied to
the Utilities' electric operations. Such procedures had been in place for SPPC's
gas distribution company. Deferred energy accounting facilitates the recovery of
costs incurred while procuring fuel and purchased power for SPPC and NPC.
The Utilities also monitor and manage credit risk with their trading
counterparties. As of December 31, 2001, the Utilities have outstanding
transactions with over 40 energy and financial services companies. The Utilities
had net credit risk with only eleven of their trading counterparties totaling
approximately $2 million as of December 31, 2001.
81
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
----
Independent Auditors' Reports .......................................................................... 83-84
Financial Statements:
Consolidated Balance Sheets as of December 31, 2001 and 2000 ................................... 85
Consolidated Statements of Income for the Years Ended December 31,
2001, 2000 and 1999 ......................................................................... 86
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 2001, 2000 and 1999 ............................................................ 87
Consolidated Statements of Common Shareholders' Equity for the
Years Ended December 31, 2001, 2000 and 1999 ................................................ 87
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999 ............................................................ 88
Consolidated Statements of Capitalization as of December 31, 2001 and 2000 ..................... 89-90
Balance Sheets for Nevada Power Company as of
December 31, 2001 and 2000 .................................................................. 91
Statements of Income for Nevada Power Company
for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 92
Statements of Cash Flows for Nevada Power Company
for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 93
Statements of Capitalization for Nevada Power
Company as of December 31, 2001 and 2000 ..................................................... 94
Consolidated Balance Sheets for Sierra Pacific Power Company as of
December 31, 2001 and 2000 .................................................................. 95
Consolidated Statements of Income for Sierra Pacific Power Company
for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 96
Consolidated Statements of Comprehensive Income for Sierra Pacific Power
Company for the Years Ended December 31, 2001, 2000 and 1999 ................................ 97
Consolidated Statements of Common Shareholders' Equity for Sierra Pacific
Power Company for the Years Ended December 31, 2001, 2000 and 1999 .......................... 97
Consolidated Statements of Cash Flows for Sierra Pacific Power Company
for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 98
Consolidated Statements of Capitalization for Sierra Pacific Power
Company as of December 31, 2001 and 2000 ..................................................... 99
Notes to Financial Statements .......................................................................... 100
82
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Sierra Pacific Resources
Reno, Nevada
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Sierra Pacific Resources and subsidiaries (the
Company) and the separate unconsolidated balance sheets and statements of
capitalization of Nevada Power Company (NPC) as of December 31, 2001 and 2000,
and the related statements of income, comprehensive income, common shareholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. Our audit also included the consolidated and unconsolidated financial
statement schedules listed in the Index at Item 14. These financial statements
and financial statement schedules are the responsibility of the Company's and
NPC'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 auditing standards generally accepted
in the United States of America. 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 financial statements present fairly, in all material
respects, the consolidated financial position of the Company and the financial
position of NPC as of December 31, 2001 and 2000, and the respective results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2001 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.
Deloitte & Touche LLP
Reno, Nevada
February 22, 2002
83
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Reno, Nevada
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Sierra Pacific Power Company and subsidiaries as
of December 31, 2001 and 2000, and the related consolidated statements of
income, comprehensive income, common shareholder's equity, and cash flows for
each of the three years in the period ended December 31, 2001. Our audits also
included the financial statement schedule listed in the Index at Item 14. 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 auditing standards generally accepted
in the United States of America. 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 the Company as of December 31, 2001
and 2000, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2001, 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, present fairly in all
material respects the information set forth therein.
Deloitte & Touche LLP
Reno, Nevada
February 22, 2002
84
SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
December 31,
2001 2000
----------- -----------
ASSETS
Utility Plant at Original Cost:
Plant in service $ 5,683,296 $ 5,269,724
Less: accumulated provision for depreciation 1,777,517 1,636,657
----------- -----------
3,905,779 3,633,067
Construction work-in-progress 203,456 347,299
----------- -----------
4,109,235 3,980,366
----------- -----------
Investments in subsidiaries and other property, net 128,892 135,062
----------- -----------
Current Assets:
Cash and cash equivalents 99,109 51,503
Accounts receivable less provision for uncollectible accounts:
2001-$39,335; 2000-$13,194 394,489 388,332
Deferred energy costs - electric (Note 1) 333,062 -
Deferred energy costs - gas (Note 1) 19,805 -
Federal income tax receivable 18,590 32,904
Materials, supplies and fuel, at average cost 94,167 75,132
Risk management assets (Note 22) 286,509 -
Other 14,071 18,442
----------- -----------
1,259,802 566,313
----------- -----------
Deferred Charges:
Goodwill, net of amortization 312,145 320,256
Deferred energy costs - electric (Note 1) 854,778 -
Deferred energy costs - gas (Note 1) 23,248 16,370
Federal income tax receivable 355,659 -
Regulatory tax asset 169,738 175,509
Other regulatory assets 102,959 105,588
Risk management assets (Note 22) 61,058 -
Risk management regulatory assets - net (Note 22) 664,383 -
Other 139,417 116,965
----------- -----------
2,683,385 734,688
----------- -----------
Net assets of discontinued operations (Note 17) - 261,479
----------- -----------
$ 8,181,314 $ 5,677,908
=========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity $ 1,702,322 $ 1,359,712
Accumulated other comprehensive income (6,986) -
Preferred stock 50,000 50,000
SPPC/ NPC obligated mandatorily redeemable preferred trust securities 188,872 237,372
Long-term debt 3,376,105 2,133,679
----------- -----------
5,310,313 3,780,763
----------- -----------
Current Liabilities:
Short-term borrowings 177,000 213,074
Current maturities of long-term debt 122,010 472,527
Accounts payable 265,250 363,242
Accrued interest 37,565 30,184
Dividends declared 1,045 20,890
Accrued salaries and benefits 30,145 28,957
Deferred taxes on deferred energy costs 123,503 -
Risk management liabilities (Note 22) 855,301 -
Other current liabilities 15,678 10,013
----------- -----------
1,627,497 1,138,887
----------- -----------
Commitments & Contingencies (Note 18)
Deferred Credits:
Deferred federal income taxes 412,658 406,310
Deferred investment tax credit 51,947 55,252
Deferred taxes on deferred energy costs 307,309
Regulatory tax liability 46,702 50,994
Customer advances for construction 108,179 109,962
Accrued retirement benefits 82,624 80,027
Risk management liabilities (Note 22) 163,636 -
Other 70,449 55,713
----------- -----------
1,243,504 758,258
----------- -----------
$ 8,181,314 $ 5,677,908
=========== ===========
The accompanying notes are an integral part of the financial statements.
85
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(Dollars in Thousands, Except Per Share Amounts)
Year ended December 31,
2001 2000 1999
------------ ------------ ------------
OPERATING REVENUES:
Electric $ 4,424,237 $ 2,219,252 $ 1,236,702
Gas 145,652 100,803 38,958
Other 18,841 14,199 9,132
------------ ------------ ------------
4,588,730 2,334,254 1,284,792
------------ ------------ ------------
OPERATING EXPENSES:
Operation:
Purchased power 4,052,077 1,116,375 373,456
Fuel for power generation 728,619 526,535 206,130
Gas purchased for resale 136,534 83,199 27,262
Deferral of energy costs - electric - net (1,136,148) 16,719 97,238
Deferral of energy costs - gas - net (23,170) (16,164) -
Other 331,961 260,496 193,391
Maintenance 69,499 52,477 59,297
Depreciation and amortization 164,640 156,035 110,075
Taxes:
Income taxes (1,230) (31,022) 25,298
Other than income 43,079 42,215 29,784
------------ ------------ ------------
4,365,861 2,206,865 1,121,931
------------ ------------ ------------
OPERATING INCOME 222,869 127,389 162,861
------------ ------------ ------------
OTHER INCOME:
Allowance for other funds used during construction 474 2,813 2,339
Other income (expense) - net 38,723 2,646 (2,325)
------------ ------------ ------------
39,197 5,459 14
------------ ------------ ------------
Total Income Before Interest Charges 262,066 132,848 162,875
------------ ------------ ------------
INTEREST CHARGES:
Long-term debt 188,370 134,596 77,494
Other 24,161 35,887 26,229
Allowance for borrowed funds used during construction and
capitalized interest (2,801) (10,634) (8,000)
------------ ------------ ------------
209,730 159,849 95,723
------------ ------------ ------------
INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 52,336 (27,001) 67,152
Preferred dividend requirements of SPPC/NPC obligated
mandatorily redeemable preferred trust securities (18,770) (18,914) (16,742)
------------ ------------ ------------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 33,566 (45,915) 50,410
Preferred stock dividend requirements of subsidiary (3,700) (3,499) (2,200)
------------ ------------ ------------
INCOME (LOSS) FROM CONTINUING OPERATIONS 29,866 (49,414) 48,210
------------ ------------ ------------
DISCONTINUED OPERATIONS:
Income from operations of water business disposed of (net of
income taxes of $888, $3,426 and $788 in 2001, 2000 and 1999,
respectively) 1,022 9,634 3,540
Gain on disposal of water business (net of income taxes of $18,237) 25,845 - -
------------ ------------ ------------
NET INCOME (LOSS) $ 56,733 $ (39,780) $ 51,750
============ ============ ============
Income (Loss) per share - Basic and Diluted
Income (Loss) from continuing operations $ 0.34 $ (0.63) $ 0.77
Income from discontinued operations 0.01 0.12 0.06
Gain on disposal of water business 0.30 - -
------------ ------------ ------------
Net income (loss) $ 0.65 (0.51) $ 0.83
============ ============ ============
Weighted Average Shares of Common Stock Outstanding 87,542,441 78,435,405 62,577,385
============ ============ ============
Annual Dividends Paid Per Share of Common Stock $ 0.65 $ 1.000 $ 1.165
============ ============ ============
The accompanying notes are an integral part of the financial statements.
86
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
Year ended December 31,
---------------------------------------------
2001 2000 1999
----------- ----------- -----------
NET INCOME (LOSS) $ 56,733 $ (39,780) $ 51,750
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Adoption of SFAS No. 133- Accounting for Derivative Instruments
and Hedging Activities:
Cummulative effect upon adoption of change in
accounting principle as of January 1 (1,923) - -
Change in market value of risk management assets and
liabilities as of December 31 (5,063) - -
Minimum pension liability adjustment - (513) 1,001
----------- ----------- -----------
OTHER COMPREHENSIVE INCOME (6,986) (513) 1,001
----------- ----------- -----------
COMPREHENSIVE INCOME $ 49,747 $ (40,293) $ 52,751
=========== =========== ===========
The accompanying notes are an integral part of the financial statements
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(Dollars in Thousands)
Year ended December 31,
---------------------------------------------
2001 2000 1999
----------- ----------- -----------
Common Stock:
Balance at Beginning of Year $ 78,475 $ 78,414 $ 54,066
Stock purchase and dividend reimbursement 23,636 61 -
Merger conversion - - 36,064
Merger cash consideration - - (11,716)
----------- ----------- -----------
Balance at End of Year 102,111 78,475 78,414
----------- ----------- -----------
Other Paid-In Capital:
Balance at Beginning of Year 1,295,221 1,293,990 683,156
Premium on sale of common stock 330,050 - -
Common stock issuance costs (13,910) - -
Purchase contract adjustment payments (13,676) - -
CSIP, DRP, ESPP and other 949 1,231 1,409
Merger transactions - - 212,148
Revaluation of pension asset - - 66,103
Goodwill - - 331,174
----------- ----------- -----------
Balance at End of Year 1,598,634 1,295,221 1,293,990
----------- ----------- -----------
Retained Earnings (Deficit):
Balance at Beginning of Year (13,984) 104,725 126,814
Income (loss) from continuing operations before preferred dividends 33,566 (45,915) 50,410
Income from discontinued operations (before preferred dividend
allocation of $200, $401, and $196 in 2001, 2000, and 1999, respectively) 1,222 10,035 3,736
Gain on disposal of water business 25,845 - -
Dividends declared and premium on redemption:
Preferred stock of subsidiaries (3,900) (3,900) (2,721)
Common stock (41,172) (78,929) (73,514)
----------- ----------- -----------
Balance at End of Year 1,577 (13,984) 104,725
----------- ----------- -----------
Total Common Shareholders' Equity at End of Year $ 1,702,322 $ 1,359,712 $ 1,477,129
=========== =========== ===========
The accompanying notes are an integral part of the financial statements
87
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year ended December 31,
2001 2000 1999
-------------- ------------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from continuing operations before preferred dividends $ 33,566 $ (45,915) $ 50,410
Income from discontinued operations before preferred dividends 1,222 10,035 3,736
Gain on disposal of water business 25,845 - -
Non-cash items included in income:
Depreciation and amortization 168,100 163,370 113,236
Deferred taxes and deferred investment tax credit 85,917 (18,564) (16,543)
AFUDC and capitalized interest (3,285) (13,858) (10,501)
Deferral of energy costs - electric - net (1,187,840) 14,884 48,313
Deferral of energy costs - gas - net (26,683) - -
Early retirement and severance amortization 3,121 4,196 1,748
Gain on disposal of water business (44,081) - -
Other non-cash (11,473) 30,972 24,122
Changes in certain assets and liabilities, net of acquisition:
Accounts receivable (1,841) (174,112) (7,393)
Materials, supplies and fuel (18,682) (1,864) (3,846)
Other current assets 4,248 (52,125) 155
Accounts payable (97,992) 224,794 49,655
Other current liabilities 14,752 16,359 (6,342)
Other - net 9,885 27,724 (35,661)
-------------- ------------- ------------
Net Cash Flows from Operating Activities (1,045,221) 185,896 211,089
-------------- ------------- ------------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Acquisition of business, net of cash acquired - - (448,311)
Additions to utility plant (334,456) (359,774) (299,064)
AFUDC and other charges to utility plant 3,285 15,227 (3,645)
Customer refunds for construction 815 (889) 8,173
Contributions in aid of construction 27,481 16,446 13,053
-------------- ------------- ------------
Net cash used for utility plant (302,875) (328,990) (729,794)
Proceeds from sale of assets of water business 318,882 - -
(Investments in) disposal of subsidiaries and other property - net (6,335) (28,056) 1,366
-------------- ------------- ------------
Net Cash Used in Investing Activities 9,672 (357,046) (728,428)
-------------- ------------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
(Decrease) increase in short-term borrowings (36,074) (547,310) 495,165
Proceeds from issuance of long-term debt 1,215,000 1,165,000 230,699
Retirement of long-term debt (323,091) (318,061) (63,293)
Redemption of preferred stock (48,500) - (26,380)
Sale of common stock 340,737 1,292 -
Dividends paid (64,917) (83,057) (115,833)
-------------- ------------- ------------
Net Cash Provided by Financing Activities 1,083,155 217,864 520,358
-------------- ------------- ------------
Net Increase in Cash and Cash Equivalents 47,606 46,714 3,019
Beginning balance in Cash and Cash Equivalents 51,503 4,789 1,770
-------------- ------------- ------------
Ending balance in Cash and Cash Equivalents $ 99,109 $ 51,503 $ 4,789
============== ============= ============
Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during period for:
Interest $ 208,390 $ 167,158 $ 127,063
Income taxes $ (55,022) $ 12,730 $ 43,719
The accompanying notes are an integral part of the financial statements
88
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
December 31,
2001 2000
----------- -----------
Common Shareholders' Equity:
Common stock $1.00 par value, authorized 250 million;
issued and outstanding 2001: 102,111,000 shares; 2000, 78,475,000 shares $ 102,111 $ 78,475
Other paid-in capital 1,598,634 1,295,221
Retained earnings (deficit) 1,577 (13,984)
----------- -----------
Total Common Shareholders' Equity 1,702,322 1,359,712
----------- -----------
Accumulated Other Comprehensive Loss (6,986) -
----------- -----------
Preferred Stock of Subsidiaries:
Not subject to mandatory redemption
Outstanding at December 31
Class A Series 1; $1.95 dividend 50,000 50,000
----------- -----------
Preferred Securities of Subsidiaries:
NPC obligated Mandatorily Redeemable Preferred Securities of NPC's Subsidiary
Trust, NVP Capital I, holding solely $122.6 million principal amount of
8.2% Junior Subordinated Debentures of NPC, due 2037 118,872 118,872
NPC obligated Mandatorily Redeemable Preferred Securities of NPC's
Subsidiary Trust, NVP Capital III, holding solely $72.2 million principal amount of
7.75% Junior Subordinated Debentures of NPC, due 2038 70,000 70,000
SPPC obligated Mandatorily Redeemable Preferred Securities of SPPC's
Subsidiary Trust, SPPC Capital I, holding solely $50 million principal amount of
8.60% Junior Subordinated Debentures of SPPC, due 2036 - 48,500
----------- -----------
Total Preferred Securities 188,872 237,372
----------- -----------
Long-Term Debt:
Unamortized bond premium and discount, net (959) (913)
Debt Secured by First Mortgage Bonds
7.63% Series L due 2002 15,000 15,000
6.70% Series V due 2022 105,000 105,000
6.60%Series W due 2019 39,500 39,500
7.20% Series X due 2022 78,000 78,000
8.50% Series Z due 2023 35,000 35,000
2.00% Series Z due 2004 56 72
2.00% Series O due 2011 1,281 1,374
6.35% Series FF due 2012 1,000 1,000
6.55% Series AA due 2013 39,500 39,500
6.30% Series DD due 2014 45,000 45,000
6.65% Series HH due 2017 75,000 75,000
6.65% Series BB due 2017 17,500 17,500
6.55% Series GG due 2020 20,000 20,000
6.30% Series EE due 2022 10,250 10,250
6.95% to 8.61% Series A MTN due 2022 110,000 110,000
7.10% and 7.14% Series B MTNdue 2023 58,000 58,000
6.62% to 6.83% Series C MTN due 2006 50,000 50,000
5.90% Series JJ due 2023 9,800 9,800
5.90% Series KK due 2023 30,000 30,000
The accompanying notes are an integral part of the financial statements.
89
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
Continued from previous page December 31,
2001 2000
----------- -----------
5.00% Series Y due 2024 3,072 3,138
6.70% Series II due 2032 21,200 21,200
5.47% Series D MTN due 2001 - 17,000
5.50% Series D MTN due 2003 5,000 5,000
5.59% Series D MTN due 2003 13,000 13,000
----------- -----------
Subtotal 781,200 798,421
----------- -----------
Industrial development revenue bonds
5.90% Series 1997A due 2032 52,285 52,285
5.90% Series 1995B due 2030 85,000 85,000
5.60% Series 1995A due 2030 76,750 76,750
5.50% Series 1995C due 2030 44,000 44,000
6.20% Series 1999B due 2004 130,000 130,000
----------- -----------
Subtotal 388,035 388,035
----------- -----------
Pollution control revenue bonds
6.38% due 2036 20,000 20,000
5.80% Series 1997B due 2032 20,000 20,000
5.30% Series 1995D due 2011 14,000 14,000
5.45% Series 1995D due 2023 6,300 6,300
5.35% Series 1995E due 2022 13,000 13,000
----------- -----------
Subtotal 73,300 73,300
----------- -----------
Variable Rate Notes
Floating rate notes due 2001 - 200,000
Floating rate notes due 2001 - 150,000
Floating rate notes due 2001 - 100,000
Floating rate notes due 2003 140,000 -
IDRB Series 2000A due 2020 100,000 100,000
PCRB Series 2000B due 2009 15,000 15,000
Water facilities notes maturing 2020 - 80,000
Floating Rate Notes due 2002 100,000 100,000
Floating Rate Notes due 2003 200,000 200,000
----------- -----------
Subtotal 555,000 945,000
----------- -----------
Debt Secured by General and Refunding Bonds:
8.25% Series A due 2011 350,000 -
8.00% Series A due 2008 320,000 -
----------- -----------
Subtotal 670,000 -
----------- -----------
Other Notes:
5.75% Series 2001 due 2036 80,000 -
6.00% Series B notes due 2003 210,000 -
8.75% Senior unsecured note Series 2000 due 2005 300,000 300,000
7.93% Senior unsecured notes due 2007 345,000 -
----------- -----------
Subtotal 935,000 300,000
----------- -----------
Obligations under capital leases 78,313 81,815
----------- -----------
Current maturities and sinking fund requirements (122,010) (472,531)
----------- -----------
Other 17,267 19,639
----------- -----------
Total Long-Term Debt 3,376,105 2,133,679
----------- -----------
TOTAL CAPITALIZATION $ 5,310,313 $ 3,780,763
=========== ===========
The accompanying notes are an integral part of the financial statements.
90
NEVADA POWER COMPANY
BALANCE SHEETS
(Dollars in Thousands)
December 31,
2001 2000
----------------- ---------------
ASSETS
Utility Plant at Original Cost:
Plant in service $ 3,356,584 $ 3,089,705
Less: accumulated provision for depreciation 928,939 855,599
----------------- ---------------
2,427,645 2,234,106
Construction work-in-progress 134,706 228,856
----------------- ---------------
2,562,351 2,462,962
----------------- ---------------
Investment in Sierra Pacific Resources (Note 1A) 309,259 471,975
Investments in subsidiaries and other property, net 12,721 13,418
----------------- ---------------
321,980 485,393
----------------- ---------------
Current Assets:
Cash and cash equivalents 8,505 43,858
Accounts receivable less provision for uncollectible accounts:
2001-$30,861; 2000-$11,605 210,333 168,890
Deferred energy costs - electric (Note 1) 281,555 -
Federal income tax receivable 18,590 18,728
Materials, supplies and fuel, at average cost 48,511 45,573
Risk management assets (Note 22) 200,829 -
Other 6,698 10,205
----------------- ---------------
775,021 287,254
----------------- ---------------
Deferred Charges:
Deferred energy costs - electric (Note 1) 698,510 -
Federal income tax receivable 295,818 -
Regulatory tax asset 109,859 113,647
Other regulatory assets 31,588 32,583
Risk management assets (Note 22) 49,493 -
Risk management regulatory assets - net (Note 22) 351,264 -
Other 29,485 25,912
----------------- ---------------
1,566,017 172,142
----------------- ---------------
$ 5,225,369 $ 3,407,751
================= ===============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity including $309,259 and $471,975
of equity in Sierra Pacific Resources in 2001 and 2000 (Note 1A) $ 1,702,322 $ 1,359,712
Accumulated other comprehensive income 520 -
NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872
Long-term debt 1,607,967 927,784
----------------- ---------------
3,499,681 2,476,368
----------------- ---------------
Current Liabilities:
Short-term borrowings 130,500 100,000
Current maturities of long-term debt 19,380 252,910
Accounts payable 202,555 157,808
Accrued interest 19,310 16,913
Dividends declared 71 86
Accrued salaries and benefits 12,450 12,297
Deferred taxes on deferred energy costs 98,544 -
Risk management liabilities (Note 22) 522,508 -
Other current liabilities 17,710 16,450
----------------- ---------------
1,023,028 556,464
----------------- ---------------
Commitments & Contingencies (Note 18)
Deferred Credits:
Deferred federal income taxes 223,641 216,753
Deferred investment tax credit 23,533 25,163
Deferred taxes on deferred energy costs 244,479 -
Regulatory tax liability 18,604 19,908
Customer advances for construction 61,454 65,588
Accrued retirement benefits 28,104 27,985
Risk management liabilities (Notes 22) 78,558 -
Other 24,287 19,522
----------------- ---------------
702,660 374,919
----------------- ---------------
$ 5,225,369 $ 3,407,751
================= ===============
The accompanying notes are an integral part of the financial statements.
91
NEVADA POWER COMPANY
STATEMENTS OF INCOME (LOSS)
(Dollars in Thousands, Except Per Share Amounts)
Year ended December 31,
------------ ------------ ------------
2001 2000 1999
------------ ------------ ------------
OPERATING REVENUES:
Electric $ 3,025,103 $ 1,325,470 $ 977,262
OPERATING EXPENSES:
Operation:
Purchased power 3,026,336 671,396 293,600
Fuel for power generation 441,900 292,787 154,546
Deferral of energy costs-net (937,322) 16,719 97,238
Other 169,442 139,723 141,041
Maintenance 45,136 34,057 50,805
Depreciation and amortization 93,101 85,989 80,644
Taxes:
Income taxes 17,775 (12,162) 19,943
Other than income 24,371 23,501 22,462
------------ ------------ ------------
2,880,739 1,252,010 860,279
------------ ------------ ------------
OPERATING INCOME 144,364 73,460 116,983
------------ ------------ ------------
OTHER INCOME (EXPENSE):
Equity in (losses) earnings of Sierra Pacific Resources (Note 1A) (6,672) (31,852) 13,058
Allowance for other funds used during construction (382) 2,456 3,713
Other income (expense) - net 27,272 1,718 (1,824)
------------ ------------ ------------
20,218 (27,678) 14,947
------------ ------------ ------------
Total Income Before Interest Charges 164,582 45,782 131,930
------------ ------------ ------------
INTEREST CHARGES:
Long-term debt 81,599 64,513 64,454
Other 13,219 13,732 8,815
Allowance for borrowed funds used during construction and
capitalized interest (2,141) (7,855) (8,356)
------------ ------------ ------------
92,677 70,390 64,913
------------ ------------ ------------
INCOME (LOSS) BEFORE NPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 71,905 (24,608) 67,017
Preferred dividend requirements of NPC obligated
mandatorily redeemable preferred trust securities (15,172) (15,172) (15,172)
------------ ------------ ------------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 56,733 (39,780) 51,845
Preferred stock dividend requirements - - (95)
------------ ------------ ------------
NET INCOME (LOSS) $ 56,733 $ (39,780) $ 51,750
============ ============ ============
Net Income (Loss) Per Share - Basic $ 0.65 $ (0.51) $ 0.83
============ ============ ============
- Diluted $ 0.65 $ (0.51) $ 0.83
============ ============ ============
Weighted Average Shares of Common
Stock Outstanding (000's) 87,542 78,435 62,577
============ ============ ============
Dividends Paid Per Share of Common Stock $ 0.65 $ 1.000 $ 1.165
============ ============ ============
The accompanying notes are an integral part of the financial statements.
92
NEVADA POWER COMPANY
STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year ended December 31,
---------------------------------------
2001 2000 1999
----------- ---------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) before preferred dividends $ 56,733 $ (39,780) $ 51,845
Non-cash items included in income:
Depreciation and amortization 93,102 85,989 80,643
Deferred taxes and deferred investment tax credit 55,085 (26,528) (18,913)
AFUDC and capitalized interest (1,759) (10,311) (12,069)
Deferral of energy costs - net (980,065) 14,884 48,313
Other non-cash 264 20,101 16,908
Equity in losses (earnings) of SPR (Note 1A) 6,672 31,852 (13,058)
Changes in certain assets and liabilities, net of acquisition:
Accounts receivable (41,444) (57,935) (11,795)
Materials, supplies and fuel (2,938) (2,465) (3,502)
Other current assets 3,507 (25,360) 1,778
Accounts payable 44,747 82,720 34,964
Other current liabilities 3,812 10,001 17,066
Other - net 4,882 30,543 (14,002)
----------- ---------- -----------
Net Cash Flows from Operating Activities (757,402) 113,711 178,178
----------- ---------- -----------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant (200,852) (204,505) (223,963)
AFUDC and other charges to utility plant 1,759 11,622 (2,184)
Customer refunds for construction (4,134) (3,753) 5,228
Contributions in aid of construction 6,331 - -
----------- ---------- -----------
Net cash used for utility plant (196,896) (196,636) (220,919)
(Investments in) disposal of subsidiaries and other property - net (115) - 1,499
----------- ---------- -----------
Net Cash Used in Investing Activities (197,011) (196,636) (219,420)
----------- ---------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings 30,500 (82,000) 77,000
Proceeds from issuance of long-term debt 815,000 365,000 129,900
Retirement of long-term debt (368,347) (205,152) (60,283)
Change in funds held in trust - - 9
Redemption of preferred stock - - (3,265)
Investment of SPR 474,921 137,000 18,000
Dividends paid (33,014) (88,308) (121,646)
----------- ---------- -----------
Net Cash Provided by Financing Activities 919,060 126,540 39,715
----------- ---------- -----------
Net (Decrease) Increase in Cash and Cash Equivalents (35,353) 43,615 (1,527)
Beginning balance in Cash and Cash Equivalents 43,858 243 1,770
----------- ---------- -----------
Ending balance in Cash and Cash Equivalents $ 8,505 $ 43,858 $ 243
=========== ========== ===========
Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during period for:
Interest $ 90,280 $ 71,430 $ 91,196
Income taxes $ (13,702) $ 6,500 $ 38,219
The accompanying notes are an integral part of the financial statements.
93
NEVADA POWER COMPANY
STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
December 31,
2001 2000
-------------- -------------
Common Shareholder's Equity:
Common stock issued $ 1 $ 1
Other paid-in capital 1,367,106 892,185
Retained earnings (deficit) 25,956 (4,449)
Equity in Sierra Pacific Resources (Note 1A) 309,259 471,975
-------------- -------------
Total Common Shareholder's Equity 1,702,322 1,359,712
-------------- -------------
Accumulated Other Comprehensive Income 520 -
-------------- -------------
Preferred Securities:
NPC obligated Mandatorily Redeemable Preferred Securities of NPC's Subsidiary
Trust, NVP Capital I, holding solely $122.6 million principal amount of
8.2% Junior Subordinated Debentures of NPC, due 2037 118,872 118,872
NPC obligated Mandatorily Redeemable Preferred Securities of NPC's Trust, NVP
Capital III, holding solely $72.2 million principal amount of 7.75% Junior
Subordinated Debentures of NPC, due 2038 70,000 70,000
-------------- -------------
Total Preferred Securities 188,872 188,872
-------------- -------------
Long-Term Debt:
Unamortized bond premium and discount, net 2 (163)
Debt Secured by First Mortgage Bonds:
7.63% Series L due 2002 15,000 15,000
6.70% Series V due 2022 105,000 105,000
6.60% Series W due 2019 39,500 39,500
7.20% Series X due 2022 78,000 78,000
8.50% Series Z due 2023 35,000 35,000
-------------- -------------
Subtotal 272,502 272,337
-------------- -------------
Industrial development revenue bonds
5.90% Series 1997A due 2032 52,285 52,285
5.90% Series 1995B due 2030 85,000 85,000
5.60% Series 1995A due 2030 76,750 76,750
5.50% Series 1995C due 2030 44,000 44,000
6.20% Series 1999B due 2004 130,000 130,000
-------------- -------------
Subtotal 388,035 388,035
-------------- -------------
Pollution Control Revenue Bonds
6.38% due 2036 20,000 20,000
5.80% Series 1997B due 2032 20,000 20,000
5.30% Series 1995D due 2011 14,000 14,000
5.45% Series 1995D due 2023 6,300 6,300
5.35% Series 1995E due 2022 13,000 13,000
-------------- -------------
Subtotal 73,300 73,300
-------------- -------------
Variable Rate Notes
Floating rate notes due 2001 - 150,000
Floating rate notes due 2001 - 100,000
Floating rate notes due 2003 140,000 -
IDRB Series 2000A due 2020 100,000 100,000
PCRB Series 2000B due 2009 15,000 15,000
-------------- -------------
Subtotal 255,000 365,000
-------------- -------------
Debt Secured by General and Refunding Bonds:
8.25% Series A due 2011 350,000 -
-------------- -------------
Other Notes:
6.0% Series B notes due 2003 210,000 -
-------------- -------------
Obligation under capital leases 78,313 81,815
-------------- -------------
Current maturities and sinking fund requirements (19,380) (252,911)
-------------- -------------
Other, excluding current portion 197 208
-------------- -------------
Total Long-Term Debt 1,607,967 927,784
-------------- -------------
TOTAL CAPITALIZATION $ 3,499,681 $ 2,476,368
============== =============
The accompanying notes are an integral part of the financial statements.
94
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
December 31,
2001 2000
---------- ----------
ASSETS
Utility Plant at Original Cost:
Plant in service $2,326,712 $2,180,019
Less: accumulated provision for depreciation 848,578 781,058
---------- ----------
1,478,134 1,398,961
Construction work-in-progress 68,750 118,442
---------- ----------
1,546,884 1,517,403
---------- ----------
Investments in subsidiaries and other property, net 57,185 60,047
---------- ----------
Current Assets:
Cash and cash equivalents 11,772 5,348
Accounts receivable less provision for uncollectible accounts:
2001 - $8,474; 2000 - $1,589 194,698 153,547
Deferred energy costs - electric 51,507 --
Deferred energy costs - gas 19,805 --
Federal income tax receivable -- 21,958
Materials, supplies and fuel, at average cost 42,290 29,209
Risk management assets (Note 22) 85,680 --
Other 5,935 7,894
---------- ----------
411,687 217,956
---------- ----------
Deferred Charges:
Deferred energy costs - electric 156,268 --
Deferred energy costs - gas 23,248 16,370
Federal income tax receivable 41,040 --
Regulatory tax asset 59,879 61,862
Other regulatory assets 51,146 61,236
Risk management assets (Note 22) 11,565 --
Risk management regulatory assets - net (Note 22) 313,119 --
Other 13,886 12,036
---------- ----------
670,151 151,504
---------- ----------
Net assets of discontinued operations (Note 17) -- 261,479
---------- ----------
$2,685,907 $2,208,389
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 692,654 $ 604,795
Accumulated other comprehensive income 247 --
Preferred stock 50,000 50,000
SPPC obligated mandatorily redeemable preferred trust securities -- 48,500
Long-term debt 923,070 605,816
---------- ----------
1,665,971 1,309,111
---------- ----------
Current Liabilities:
Short-term borrowings 46,500 108,962
Current maturities of long-term debt 2,630 219,616
Accounts payable 95,555 166,134
Accrued interest 8,408 6,992
Dividends declared 974 23,975
Accrued salaries and benefits 15,466 15,475
Deferred taxes on deferred energy costs 24,959 --
Risk management liabilities (Note 22) 332,793 --
Other current liabilities 3,387 2,932
---------- ----------
530,672 544,086
---------- ----------
Commitments & Contingencies (Note 18)
Deferred Credits:
Deferred federal income taxes 178,533 179,106
Deferred investment tax credit 28,414 30,088
Deferred taxes on deferred energy costs 62,831 --
Regulatory tax liability 28,098 31,087
Customer advances for construction 46,725 41,776
Accrued retirement benefits 43,028 44,374
Risk management liabilities (Note 22) 77,324 --
Other 24,311 28,761
---------- ----------
489,264 355,192
---------- ----------
$2,685,907 $2,208,389
========== ==========
The accompanying notes are an integral part of the financial statements.
95
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
December 31,
2001 2000 1999
----------- ----------- -----------
OPERATING REVENUES:
Electric $ 1,399,134 $ 893,782 $ 609,197
Gas 145,652 100,803 100,177
----------- ----------- -----------
1,544,786 994,585 709,374
----------- ----------- -----------
OPERATING EXPENSES:
Operation:
Purchased power 1,025,741 444,979 179,781
Fuel for power generation 286,719 233,748 115,065
Gas purchased for resale 136,534 83,199 68,125
Deferral of energy costs - electric - net (198,826) -- --
Deferral of energy costs - gas - net (23,170) (16,164) --
Other 117,627 96,438 92,745
Maintenance 24,363 18,420 20,309
Depreciation and amortization 70,358 69,350 69,762
Taxes:
Income taxes 8,507 (672) 33,870
Other than income 17,965 18,152 17,014
----------- ----------- -----------
1,465,818 947,450 596,671
----------- ----------- -----------
OPERATING INCOME 78,968 47,135 112,703
----------- ----------- -----------
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction 856 357 (1,370)
Other income (expense) - net 8,489 (2,429) (673)
----------- ----------- -----------
9,345 (2,072) (2,043)
----------- ----------- -----------
Total Income 88,313 45,063 110,660
----------- ----------- -----------
INTEREST CHARGES:
Long-term debt 55,199 36,865 31,151
Other 7,433 11,312 11,286
Allowance for borrowed funds used during construction and
capitalized interest (660) (2,779) (141)
----------- ----------- -----------
61,972 45,398 42,296
----------- ----------- -----------
INCOME (LOSS) BEFORE SPPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 26,341 (335) 68,364
Preferred dividend requirements of SPPC obligated
mandatorily redeemable preferred trust securities
(3,598) (3,742) (3,749)
----------- ----------- -----------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS 22,743 (4,077) 64,615
Preferred dividend requirements and premium paid on redemption (3,700) (3,499) (4,957)
----------- ----------- -----------
NET INCOME (LOSS) FROM CONTINUING OPERATIONS 19,043 (7,576) 59,658
----------- ----------- -----------
DISCONTINUED OPERATIONS:
Income from operations of water business disposed of (net of income taxes of
$888, $3,426 and $2,172 in 2001, 2000 and 1999 respectively) 1,022 9,634 6,583
Gain on disposal of water business (net of income taxes of $18,237) 25,845 -- --
----------- ----------- -----------
NET INCOME $ 45,910 $ 2,058 $ 66,241
=========== =========== ===========
The accompanying notes are an integral part of the financial statements
96
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
Year ended December 31,
---------------------------
2001 2000 1999
------- ------- -------
NET INCOME $45,910 $ 2,058 $66,241
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Adoption of SFAS No. 133- Accounting for Derivative Instruments
and Hedging Activities:
Cumulative effect upon adoption of change in 211 -- --
accounting principle as of January 1
Change in market value of risk management and
liabilities as of December 31 36
------- ------- -------
OTHER COMPREHENSIVE INCOME 247 -- --
------- ------- -------
COMPREHENSIVE INCOME $46,157 $ 2,058 $66,241
======= ======= =======
The accompanying notes are an integral part of the financial statements
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(Dollars in Thousands)
Year ended December 31,
2001 2000 1999
--------- --------- ---------
Common Stock:
Balance at Beginning of Year
and End of Year $ 4 $ 4 $ 4
--------- --------- ---------
Other Paid-In Capital:
Balance at Beginning Year 598,684 584,684 562,684
Additional investment by parent company 104,949 14,000 22,000
--------- --------- ---------
Balance at End of Year 703,633 598,684 584,684
--------- --------- ---------
Retained (Deficit) Earnings:
Balance at Beginning of Year 6,107 89,050 98,679
Income (Loss) before preferred dividends of continuing operations 22,743 (4,077) 64,615
Income from discontinued operations (before preferred dividend
allocation of $200, $401, and $528 in 2001, 2000, and 1999, respectively) 1,222 10,034 7,111
Gain on disposal of water business 25,845 -- --
Preferred stock dividends declared and premium on redemption (3,900) (3,900) (5,355)
Common stock dividends declared (63,000) (85,000) (76,000)
--------- --------- ---------
Balance at End of Year (10,983) 6,107 89,050
--------- --------- ---------
Total Common Shareholder's Equity at
End of Year $ 692,654 $ 604,795 $ 673,738
========= ========= =========
The accompanying notes are an integral part of the financial statements
97
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31,
2001 2000 1999
--------- --------- ---------
Cash Flows From Operating Activities:
Income (loss) from continuing operations before preferred dividends $ 22,743 $ (4,077) $ 64,615
Income from discontinued operations before preferred dividends 1,222 10,035 7,111
Gain on disposal of water business 25,845 -- --
Non-cash items included in income:
Depreciation and amortization 73,818 76,685 77,373
Deferred taxes and investment tax credits 57,382 7,935 5,595
AFUDC and capitalized interest (1,526) (3,547) 1,033
Deferral of energy costs - electric - net (207,775) -- --
Deferral of energy costs - gas - net (26,683) -- --
Early retirement and severance amortization 3,121 4,196 4,194
Gain on disposal of water business (44,081) -- --
Other non-cash (386) 10,871 8,644
Changes in certain assets and liabilities:
Accounts receivable (36,835) (41,604) 685
Materials, supplies and fuel (12,728) 508 (4,294)
Other current assets 1,836 (26,749) (411)
Accounts payable (70,579) 87,643 12,459
Other current liabilities 2,380 1,231 (23,257)
Other-net (1,333) (11,117) (31,418)
--------- --------- ---------
Net Cash Flows from Operating Activities (213,579) 112,010 122,329
--------- --------- ---------
Cash Flows From (Used in) Investing Activities:
Additions to utility plant (133,604) (155,269) (142,306)
AFUDC and other charges to utility plant 1,526 3,605 (768)
Customer refunds for construction 4,949 2,864 5,120
Contributions in aid of construction 21,150 16,446 21,823
--------- --------- ---------
Net cash used for utility plant (105,979) (132,354) (116,131)
Proceeds from sale of assets of water business 318,882 -- --
Disposal of (investments in) subsidiaries and other property - net 2,747 2,292 (28,720)
--------- --------- ---------
Net Cash From (Used in) Investing Activities 215,650 (130,062) (144,851)
--------- --------- ---------
Cash Flows From Financing Activities
(Decrease) increase in short-term borrowings (62,462) (5,915) 1,972
Proceeds from issuance of long-term debt 400,000 200,000 124,495
Retirement of long-term debt (299,732) (102,797) (33,270)
Redemption of preferred stock (48,500) -- (23,115)
Investment by parent company 104,948 14,000 22,000
Dividends paid and premiums on preferred redemption (89,901) (84,899) (81,746)
--------- --------- ---------
Net Cash Provided by Financing Activities 4,353 20,389 10,336
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 6,424 2,337 (12,186)
Beginning Balance in Cash and Cash Equivalents 5,348 3,011 15,197
--------- --------- ---------
Ending Balance in Cash and Cash Equivalents $ 11,772 $ 5,348 $ 3,011
========= ========= =========
Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during year for:
Interest $ 66,597 $ 57,331 $ 54,303
Income taxes (25,632) 9,644 28,604
The accompanying notes are an integral part of the financial statements.
98
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
December 31,
2001 2000
----------- -----------
Common Shareholder's Equity:
Common stock, $3.75 par value,
1,000 shares authorized, issued and outstanding $ 4 $ 4
Other paid-in capital 703,633 598,684
Retained (deficit) earnings (10,983) 6,107
----------- -----------
Total Common Shareholder's Equity 692,654 604,795
----------- -----------
Accumulated Other Comprehensive Income 247 --
----------- -----------
Cumulative Preferred Stock:
Not subject to mandatory redemption
$25 stated value
Class A Series 1; $1.95 dividend 50,000 50,000
----------- -----------
Preferred Securities
SPPC-obligated mandatorily redeemable preferred securites
of SPPC's subsidiary trust, Sierra Pacific Power
Capital I, holding solely $50 million principal amount of
8.60% junior subordinated debentures of the Company, due 2036 -- 48,500
----------- -----------
Long Term Debt:
Unamortized bond premium and discount, net (961) (750)
Debt Secured by First Mortgage Bonds
2.00% Series Z due 2004 56 72
2.00% Series O due 2011 1,281 1,374
6.35% Series FF due 2012 1,000 1,000
6.55% Series AA due 2013 39,500 39,500
6.30% Series DD due 2014 45,000 45,000
6.65% Series HH due 2017 75,000 75,000
6.65% Series BB due 2017 17,500 17,500
6.55% Series GG due 2020 20,000 20,000
6.30% Series EE due 2022 10,250 10,250
6.95% to 8.61% Series A MTN due 2022 110,000 110,000
7.10% and 7.14% Series B MTN due 2023 58,000 58,000
6.62% to 6.83% Series C MTN due 2006 50,000 50,000
5.90% Series JJ due 2023 9,800 9,800
5.90% Series KK due 2023 30,000 30,000
5.00% Series Y due 2024 3,072 3,138
6.70% Series II due 2032 21,200 21,200
5.47% Series D MTN due 2001 -- 17,000
5.50% Series D MTN due 2003 5,000 5,000
5.59% Series D MTN due 2003 13,000 13,000
----------- -----------
Subtotal 508,698 526,084
----------- -----------
Variable Rate Notes
Water facilities notes maturing 2020 -- 80,000
Floating rate notes due 2001 -- 200,000
----------- -----------
Subtotal -- 280,000
----------- -----------
Debt Secured by General and Refunding Bonds
8.00% Series A due 2008 320,000 --
----------- -----------
Other Notes:
5.75% Series 2001 due 2036
80,000 --
----------- -----------
Other 17,002 19,348
----------- -----------
Current maturities and sinking fund requirements (2,630) (219,616)
----------- -----------
Total Long-Term Debt 923,070 605,816
----------- -----------
TOTAL CAPITALIZATION $ 1,665,971 $ 1,309,111
=========== ===========
The accompanying notes are an integral part of the financial statements.
99
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:
General
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), Nevada Electric Investment Company
(NEICO), Sierra Pacific Energy Company (SPE), Sierra Water Development Company
(SWDC) and, Sierra Gas Holding Company (SGHC). All significant intercompany
balances and intercompany transactions have been eliminated in consolidation.
See Note 2 for additional information regarding the presentation of consolidated
financial results pursuant to the 1999 merger of SPR and NPC.
NPC is an operating public utility that provides electric service in Clark
County in southern Nevada. The assets of NPC represent 60% of the consolidated
assets of SPR at December 31, 2001. NPC provides electricity to approximately
639,000 customers in the communities of Las Vegas, North Las Vegas, Henderson,
Searchlight, Laughlin and adjoining areas. Service is also provided to Nellis
Air Force Base and the Department of Energy at Mercury and Jackass Flats at the
Nevada Test Site. The consolidated financial statements of SPR include the
accounts of NPC's wholly owned subsidiaries, NVP Capital I and NVP Capital III.
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 33% of
the consolidated assets of SPR at December 31, 2001. SPPC provides electricity
to approximately 315,000 customers in a 50,000 square mile service area
including western, central and northeastern Nevada, including the cities of
Reno, Sparks, Carson City, Elko, and a portion of eastern California, including
the Lake Tahoe area. The consolidated financial statements of SPR include the
accounts of SPPC's wholly owned subsidiaries, Pinon Pine Corporation, Pinon 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 is 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 accounts for its joint
venture interest under the equity method. e.three provides comprehensive energy
services in commercial and industrial markets on a regional basis. SPE markets a
package of telecommunication products and services. SPC was formed in 1999 to
provide telecommunications services using fiber optic cable technology in both
northern and southern Nevada. Also, SPC and a subsidiary of Montana Power
Company are in a partnership that is constructing a fiber optic line between
Salt Lake City, Utah and Sacramento, CA.
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles 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
100
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.
Certain reclassifications of prior year information have been made for
comparative purposes but have not affected previously reported net income or
common shareholders' equity.
Deferral of Energy Costs
Nevada and California statutes permit regulated utilities to, from
time-to-time, adopt deferred energy accounting procedures. The intent of these
procedures is to ease the effect of fluctuations in the cost of purchased gas,
fuel and purchased power. 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
income statement 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. AB 369 requires the
Utilities to use deferred energy accounting for their respective electric
operations beginning on March 1, 2001, and to file applications to clear their
respective deferred energy account balances at least every 12 months. See Note 3
for additional information on the deferred energy accounting provisions of AB
369.
NPC utilized deferred energy accounting procedures in 1999, and part of
2000. NPC ceased utilizing deferred energy accounting effective August 1, 2000,
and resumed those procedures on March 1, 2001. During 1999, SPPC did not employ
deferred energy accounting procedures, but resumed those procedures for natural
gas operations as of January 1, 2000, and for its electric operations on March
1, 2001.
Utility Plant
In addition to direct labor and material costs, the Utilities also charge
the following to the cost of constructing utility plant: the cost of time spent
by administrative employees in planning and directing construction work;
property taxes; employee benefits (including such costs as pensions,
postretirement and postemployment benefits, vacations and payroll taxes); and an
allowance for funds used during construction (AFUDC).
The original cost of plant retired or otherwise disposed of and the cost of
removal less salvage is generally charged to the accumulated provision for
depreciation. The cost of current repairs and minor replacements is charged to
operating expenses when incurred. The cost of renewals and betterments is
capitalized.
Allowance For Funds Used During Construction and Capitalized Interest
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 Public Utility Commission of Nevada ("PUCN").
AFUDC is capitalized in the same manner as construction labor and material
costs, 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 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 rates used during 2001, 2000, and 1999 were 8.32%, 8.34%, and 8.55%,
respectively. SPPC's AFUDC rates used during 2001, 2000, and 1999 were 7.94%,
101
7.17%, and 6.09%, respectively. As specified by the PUCN, certain projects were
assigned a lower AFUDC rate due to specific low-interest-rate financings
directly associated with those projects.
Depreciation
Depreciation is calculated using the straight-line composite method over
the estimated remaining service lives of the related properties. NPC's
depreciation provision for 2001, 2000, and 1999, as authorized by the PUCN and
stated as a percentage of the original cost of depreciable property, was
approximately 2.9%. SPPC's depreciation provision for 2001, 2000, and 1999, as
authorized by the PUCN and stated as a percentage of the original cost of
depreciable property, was approximately 3.21%, 3.21%, and 3.14%, respectively.
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.
Regulatory Accounting and Other Regulatory Assets
The Utilities' rates are currently subject to the approval of the PUCN 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. SFAS No. 101,
"Regulated Enterprises-Accounting for the Discontinuation of Application of FASB
Statement No. 71", requires that an enterprise whose operations cease to meet
the qualifying criteria of SFAS No. 71 discontinue the application of that
statement by eliminating the effects of any actions of regulators that had been
previously recognized.
In conformity with SFAS No. 71, the accounting for the Utilities conforms
to generally accepted accounting principles as applied to regulated public
utilities and as prescribed by the agencies and commissions of the jurisdictions
in which they operate. In accordance with these principles, certain costs that
would otherwise be charged to expense or capitalized as plant costs are deferred
as regulatory assets based on expected recovery from customers in future rates.
Management's expected recovery of deferred costs is based upon specific
ratemaking decisions or precedent for each item. The following other regulatory
assets were included in the consolidated balance sheets of SPR as of December 31
(dollars in thousands):
102
DESCRIPTION 2001 2000 AMORTIZATION PERIODS
--------------------------------------- ---- ---- ---------------------------
Early retirement and severance offers $ 7,701 $ 12,567 Various through 2004
Loss on reacquired debt 32,882 32,548 Various through 2030
Plant assets 3,783 3,964 Various through 2031
Merger transition costs 10,543 8,275 To be determined
Merger severance/relocation 21,851 22,434 To be determined
Merger goodwill 19,675 11,533 To be determined
Other costs 6,524 14,267 Various
---------- ---------
Total $ 102,959 $ 105,588
========= =========
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 utilities might be required to
reduce their asset balances to reflect a market basis less than cost.
Discontinuance of cost-based regulation would 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.
Management periodically assesses whether the requirements for application
of SFAS 71 are satisfied. The provisions of AB 369, signed into law in April
2001, include the repeal of all statutes authorizing retail competition in
Nevada's electric utility industry. Accordingly, the Utilities continue to apply
regulatory accounting to the generation, transmission and distribution portions
of their businesses.
Federal Income Taxes and Investment Tax Credits
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. Deferred taxes are provided on temporary
differences at the statutory income tax rate in effect as of the most recent
balance sheet date.
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 bases 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.
Investment tax credits are no longer available to the Utilities. The
deferred investment tax credits are being amortized over the estimated service
lives of the related properties.
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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.
Recent Pronouncements
Financial Accounting Standards Board
In June 2001, the FASB issued three new pronouncements, SFAS No. 141,
"Business Combinations," SFAS No. 142, "Goodwill and Other Intangible Assets,"
and SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 141
requires that the purchase method of accounting be used for all business
combinations initiated after June 30, 2001. SFAS No. 142, adopted January 1,
2002, changes the accounting for goodwill from an amortization method to one
requiring at least an annual review for impairment. Due to the regulatory
treatment anticipated for most of SPR's goodwill, Management does not expect
SFAS No. 142 to have a material effect on the financial position or results of
operations of SPR, NPC, and SPPC. SFAS No. 143, effective for fiscal years
beginning after June 15, 2002, requires an entity to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. Management does not expect the adoption of SFAS No. 143 to have a
material effect on the financial position or results of operations of SPR, NPC,
and SPPC.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This standard provides guidance on
the impairment of long-lived assets and for long-lived assets to be disposed of.
The standard supersedes the current authoritative literature on impairments as
well as disposal of a segment of a business and was adopted January 1, 2002.
Note 1A. FINANCIAL STATEMENTS OF NEVADA POWER COMPANY
As described in Note 2 that follows, NPC was deemed to be the acquirer of
SPR for accounting purposes as reflected in the SPR Consolidated Financial
Statements. However, after the merger with SPR and as a result of the structure
of the transactions, NPC is a separate legal entity, which is a wholly owned
subsidiary of SPR. As a legal matter, NPC does not own any equity interest in
SPR. The audited NPC Financial Statements accommodate the presentation of
financial information of NPC on a stand-alone basis by summarizing all non-NPC
financial information into a few items on each of the Financial Statements.
These summarized items are repeated below (in 000's):
Non-NPC financial items on the NPC Financial Statements
NPC Balance Sheet: December 31, 2001 December 31, 2000
------------------ ----------------- -----------------
Investment in Sierra Pacific Resources $309,259 $471,975
Equity in Sierra Pacific Resources $309,259 $471,975
The Investment in Sierra Pacific Resources reflects the net assets, after
deducting for all liabilities and preferred stock of Sierra Pacific Resources
not related to NPC. The Equity in Sierra Pacific Resources reflects the sum of
paid-in-capital and retained earnings of SPR, without the benefit of NPC.
These line items are presented under the rules of purchase accounting and
do not represent any asset to which holders of NPC's securities may look for
recovery of their investment. These items must be disregarded for determining
the ability of NPC to satisfy its obligations or to pay dividends (preferred or
common), for
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calculating NPC's ratios of earnings to fixed charges and preferred stock
dividends, and for all of NPC's financial covenants and earnings tests including
those under its charter and mortgage.
NPC Income Statement: Year Ended Year Ended Year Ended
--------------------- ---------- ---------- ----------
December 31, 2001 December 31, 2000 December 31, 1999
----------------- ----------------- -----------------
Equity in (Losses) Earnings of Sierra Pacific
Resources $(6,672) $(31,852) $13,058
The Equity in (Losses) Earnings of Sierra Pacific Resources represents the
net income (loss) of SPR after SPPC preferred stock dividends.
This line item is presented under the rules of purchase accounting and does
not represent any item of revenue or income to which holders of NPC's securities
may look for recovery of their investment. This item must be disregarded for
determining the ability of NPC to satisfy its obligations or its ability to pay
dividends (preferred or common), for calculating NPC's ratios of earnings to
fixed charges and preferred dividends, and for all of NPC's financial covenants
and earnings tests including those under its charter and mortgage.
NPC Statement of Cash Flow: Year Ended Year Ended Year Ended
--------------------------- ---------- ---------- ----------
December 31, 2001 December 31, 2000 December 31, 1999
----------------- ----------------- -----------------
Equity in (Losses) Earnings of Sierra Pacific
Resources $(6,672) $(31,852) $13,058
As in the Income Statement, the Equity in (Losses) Earnings of Sierra
Pacific Resources represents the net income (loss) of SPR, after SPPC preferred
stock dividends.
This line item is presented under the rules of purchase accounting and does
not represent any item of cash flow to which holders of NPC's securities may
look for recovery of their investment. This item must be disregarded for
determining the ability of NPC to satisfy its obligations or its ability to pay
dividends (preferred or common), for calculating NPC's ratios of earnings to
fixed charges and preferred dividends, and for all of NPC's financial covenants
and earnings tests including those under its charter and mortgage.
NPC Statement of Capitalization: December 31, 2001 December 31, 2000
-------------------------------- ----------------- -----------------
Equity in Sierra Pacific Resources $309,259 $471,975
The Equity in Sierra Pacific Resources reflects the sum of paid-in-capital
and retained earnings of SPR on NPC's books.
This line item is presented under the rules of purchase accounting and does
not represent any item of cash flow to which holders of NPC's securities may
look for recovery of their investment. This item must be disregarded for
determining the ability of NPC to satisfy its obligations or its ability to pay
dividends (preferred or common), for calculating NPC's ratios of earnings to
fixed charges and preferred dividends, and for all of NPC's financial covenants
and earnings tests including those under its charter and mortgage.
NOTE 2. SIERRA PACIFIC RESOURCES AND NEVADA POWER MERGER
On July 28, 1999, the merger between SPR and NPC was consummated. The
merger was accounted for as a reverse purchase under generally accepted
accounting principles, with NPC considered the acquiring entity even though SPR
is the surviving legal entity. In addition, for accounting purposes the merger
was deemed to have occurred on August 1, 1999. As a result of this reverse
purchase accounting treatment: (i) the historical financial statements of SPR
for periods prior to the date of the merger are no longer the financial
statements of SPR, and therefore, are no longer presented; (ii) the historical
financial statements of SPR for periods prior to the date of the merger are
those of NPC; and (iii) based on a merger date of August 1, 1999, the
Consolidated Statements of Income for the twelve months ended December 31, 1999,
include five months (August through
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December 1999) of operating activity for SPR and its subsidiaries other than
NPC. The same statements include the operating results of NPC for the entire
periods presented
Through December 31, 2001, SPR incurred a total of $60.2 million in
capitalized costs since merger work began. The capitalized merger amounts
consist of $38.4 million of transaction and transition costs and $21.8 million
of employee separation costs.
Employee severance, relocation, and related costs for SPR were $17.3
million, of which $.4 million remains unpaid as of December 31, 2001. Other
costs incurred in connection with employee separations included pension and
postretirement benefits net of plan curtailment gains of $4.5 million.
In accordance with the terms of the merger, each outstanding share of SPR's
common stock was converted into the right to receive either $37.55 in cash or
1.44 shares of newly issued SPR common stock. Each outstanding share of NPC
common stock was converted to the right to receive either $26.00 in cash or 1.00
share of newly issued SPR common stock. 4,037,000 shares of SPR and 11,716,611
shares of NPC common stock were exchanged for $151.6 million and $304.6 million,
respectively. The remaining shares of each company were converted to newly
issued shares of SPR common stock. SPR stockholders and NPC stockholders
received 38,866,054 and 39,548,506 shares, respectively, of newly issued SPR
common stock, resulting in 78,414,560 outstanding shares of SPR on August 1,
1999.
The total consideration paid to SPR common stockholders was equal to cash
of $151.6 million and 38,866,054 shares of newly issued SPR common stock at a
price of $24.18 per share based on the average closing price of NPC common stock
between April 22, 1998 and May 6, 1998. The eleven-day average price of NPC
common stock used in determining the total stock consideration represents the
market price over a reasonable period of time before and after the transaction
was announced on April 29, 1998. Goodwill of $331.2 million was recorded in
connection with the merger. The order of the PUCN approving the merger allowed
SPR to defer merger costs (including goodwill) allocable to the regulated
Utilities for a three-year period. Accordingly, goodwill amortization through
December 31, 2001, associated with the regulated Utilities has been reclassified
to a regulatory asset.
On October 1, 2001, and November 30, 2001, NPC and SPPC, respectively,
filed applications with the PUCN for general rate increases that included, among
other items, a request to recover deferred merger costs, including goodwill. The
Utilities have proposed to recover merger transition and transaction costs over
ten years and goodwill over forty years. Decisions on the NPC and SPPC cases are
expected no later than April 1, 2002, and June 1, 2002, respectively. See Note 3
"Regulatory Actions" for additional information about these rate cases.
NOTE 3. REGULATORY ACTIONS
Nevada Matters (NPC and SPPC)
- -----------------------------
The Utilities are subject to the jurisdiction of the PUCN and, in the case
of SPPC, the California Public Utility Commission (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 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
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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.
Nevada Legislation
- ------------------
On April 18, 2001, the Governor of Nevada signed into law AB 369. The
provisions of AB 369 include a moratorium on the sale of generation assets by
electric utilities, the repeal of electric industry restructuring, and a
reinstatement of deferred energy accounting for fuel and purchased power costs
incurred by electric utilities. Set forth below is a summary of key provisions
of AB 369.
Generation Divestiture Moratorium
AB 369 prohibits all divestiture of generation assets by electric utilities
until July 2003. After January 1, 2003, NPC or SPPC may seek PUCN permission to
sell one or more generation assets with the sale to be effective on or after
July 1, 2003. The PUCN may approve the request to divest only if it finds the
transaction to be in the public interest. The PUCN may base its approval of the
request upon such terms, conditions, or modifications as it deems appropriate.
AB 369 directs the PUCN to take all steps necessary to obtain federal
approval for the prohibition on divestiture and to vacate any of its own orders
that had previously approved generation divestiture transactions.
Deferred Energy Accounting
AB 369 required the Utilities to use deferred energy accounting for their
respective electric operations beginning on March 1, 2001. The intent of
deferred energy accounting is to ease the effect of fluctuations in the cost of
purchased power and fuel. 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
income statement 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.
AB 369 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, AB 369 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 to recover, a carrying charge on such deferred balances.
AB 369 requires that each Utility file an application to clear its deferred
energy account balances after the end of each 12-month period, but allows the
balances from each 12-month period to be recovered over an adjustment period of
up to three years in order to reduce the volatility of rate changes. In
addition, after the initial deferred energy case, each utility is allowed to
file an application to clear its deferred energy account balances after the end
of a six-month period if the proposed net increase or decrease in fuel and
purchased power revenues for the six-month period is more than 5%. If a utility
using deferred energy accounting realizes a rate of return greater than the rate
authorized by the PUCN, the portion that exceeds the authorized rate of return
will be transferred to the next deferred energy adjustment period.
Before an electric utility may clear its deferred accounts, AB 369 requires
the PUCN to determine whether the costs for purchased fuel and purchased power
that the electric utility recorded in its deferred
107
accounts are recoverable and whether the revenues that the electric utility
collected from customers in Nevada for purchased fuel and purchased power are
properly recorded and credited in its deferred accounts. AB 369 prohibits the
PUCN from allowing an electric utility to recover any costs for purchased fuel
and purchased power that were the result of any practice or transaction that was
undertaken, managed or performed imprudently by the electric utility. To the
extent that the PUCN finds that any amount included in either Utility's deferred
account was imprudently incurred, the PUCN will not permit that amount to be
recovered through higher rates, and an equivalent amount of the Utility's
deferred energy costs asset will be required to be written off. Such a write-off
could cause a substantial loss to be incurred by the Utility, could cause its
securities to be downgraded by the rating agencies, and could make it
significantly more difficult to finance the operations of the Utility and to buy
fuel and purchased power from third parties.
In addition, as discussed under "Required Filings" below, the PUCN must
determine whether the rates that went into effect on March 1, 2001, pursuant to
the CEP as filed by the Utilities with the PUCN on January 29, 2001, are just
and reasonable and reflect prudent business practices.
Transition of Rates to Deferred Energy Accounting
All rates in effect on April 1, 2001, including the cumulative increases
under the Global Settlement and the CEP Riders, remain in effect until the PUCN
issues final orders on future general and initial deferred energy rate
applications. (See "Required Filings," below). No further applications can be
made for the Fuel and Purchased Power (F&PP) riders that were part of the July
2000 Global Settlement described in SPR's Annual Report on Form 10-K for the
year ended December 31, 2000.
The Utilities are not permitted to recover any shortfall incurred before
March 1, 2001, resulting from the difference between actual fuel and purchased
power costs and the rates permitted by the Global Settlement. Although the F&PP
riders were in effect during this period, the riders were based on trailing
12-month average costs and were subject to caps and, therefore, did not allow
the Utilities full recovery for fuel and purchased power costs due to the rapid
rise in energy prices.
AB 369 prohibits the PUCN from taking any further action on the CEP, and
provides that, except for the CEP Rider rate increases put in effect on April 1,
2001, the CEP will be deemed to have been withdrawn by the Utilities.
Additionally, approximately $20 million of revenue collected by the Utilities
based on the CEP before April 1, 2001 was credited to the deferred energy
accounts, which caused the accounts to start in an over-collected position.
Required Filings
The Utilities have both filed a general rate application and a deferred
energy application on the dates listed below:
General Rate Case Deferred Energy Filing
----------------- ----------------------
File Date Effective Date File Date Effective Date
Nevada Power Company Oct. 1, 2001 April 1, 2002 Dec. 1, 2001 April 1, 2002
Sierra Pacific Power Company Dec. 1, 2001 June 1, 2002 Feb. 1, 2002 June 1, 2002
In connection with clearing the Utilities' deferred energy accounts, the
PUCN must investigate and determine whether the Utilities' rates that went into
effect on March 1, 2001, pursuant to the CEP, are just and reasonable and
reflect prudent business practices. The rates in effect on April 1, 2001, remain
in effect until the PUCN issues final orders on the general and initial deferred
energy rate applications referred to above. The PUCN is prohibited from
adjusting rates during this time period unless an adjustment is absolutely
necessary to avoid a finding that the rates are confiscatory and, therefore, in
violation of the United States or Nevada
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Constitutions. If adjustments are necessary, they may only be made to the extent
necessary to avoid an unconstitutional result.
After the initial general rate applications described above, each Utility
will be required to file future general rate applications at least every 24
months.
Restrictions on Mergers and Acquisitions
AB 369 imposes certain restrictions on mergers and acquisitions involving
Nevada electric utilities. In particular, the PUCN may not approve a merger or
acquisition involving an electric utility unless the utility complies with the
generation divestiture provisions of AB 369.
In addition, AB 369 includes provisions that would have significantly
affected the required regulatory approvals for the proposed acquisition of PGE
from Enron. On April 26, 2001, Enron and SPR terminated, by mutual agreement,
the proposed purchase and sale of PGE.
AB 369 also provides that if an electric utility holding company acquires
an interest in an out-of-state public utility prior to July 1, 2003, each
electric utility in which the holding company holds a controlling interest shall
not be entitled to the benefit of deferred energy accounting. Thus, in the event
that SPR acquires an out-of-state public utility, NPC and SPPC would lose the
ability to utilize deferred energy accounting.
Repeal of Electric Industry Restructuring
AB 369 repeals all statutes authorizing retail competition in Nevada's
electric utility industry and voids any license issued to an alternative seller
in connection with retail electric competition.
Other Legislation
SB 372, which increased renewable energy portfolio requirements, was
enacted in the 2001 Nevada legislative session. Renewable resources include
biomass, wind, solar, and geothermal projects. In 2003, the Utilities will be
required to purchase five percent of their energy from renewable resources.
These requirements increase to 15% by 2013. Prior law capped renewable energy
requirements at one percent. Currently, SPPC obtains approximately nine percent
of its energy from renewable resources, while NPC obtains less than one percent
from renewables. SB 372 requires the PUCN to establish standards for renewable
energy contracts, including prices and other terms and conditions. If sufficient
renewable energy contracts that meet PUCN standards are not available, the
Utilities will not be required to meet the portfolio requirements. All renewable
energy contracts meeting PUCN standards will be recoverable in the deferred
energy accounts.
The 2001 Nevada legislature passed another key piece of legislation for the
Nevada energy industry, AB 661. AB 661 allows commercial and governmental
customers with an average demand greater than 1 MW to select new energy
suppliers. The Utilities would continue to provide transmission, distribution,
metering and billing services to such customers. AB 661 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 the Utilities, remaining
customers or the utility cannot be negatively impacted by the departure, and the
departing customers must pay any deferred energy balances. The PUCN has adopted
regulations prescribing the criteria that will be used to determine if there
will be negative impacts to remaining customers or the utility. Certain limits
are placed upon the departure of NPC customers until 2003; most significantly,
the amount of load departing is limited to approximately 1100 MW in peak
conditions. AB 661 permits customers to file applications with the PUCN
beginning in the fourth quarter of 2001. Customers must provide 180-day notice
to the Utilities and could begin to receive service from new
109
suppliers by mid-2002. On January 10, 2002, an approximately 130 MW SPPC
customer submitted an application to the PUCN under AB 661. The customer, SPPC,
and PUCN staff are negotiating a stipulation regarding settlement of the terms
and conditions under which this customer will be permitted to procure energy
from an alternative source other than SPPC. The terms and conditions of the
stipulation are expected to comply with the provisions of AB 661 in that SPPC
and its remaining customers will not be negatively impacted by the customer's
departure. A hearing on the stipulation has been set for March 20, 2002.
AB 661 also contains new electric and gas energy surcharges for low-income
assistance and weatherization programs. These surcharges are recoverable
directly from customers as separate line items on their bills with the Utilities
remitting collected surcharges to the PUCN. Various state agencies will
administer the disposition of the funds.
Nevada Power Company General Rate Case (NPC)
On October 1, 2001, NPC filed an application with the PUCN seeking an
electric general rate increase. This application was mandated by AB 369, which
was enacted by the Nevada legislature in April 2001. On December 21, 2001, NPC
filed a Certification to its general rate filing updating costs and revenues
pursuant to Nevada regulations. In the certification filing, NPC requested an
increase in its general rates charged to all classes of electric customers
designed to produce an increase in annual electric revenues of $22.7 million,
which is an overall 1.7% rate increase. The application also seeks a return on
common equity ("ROE") for Nevada Power's total electric operations of 12.25% (a
reduction from NPC's last-authorized ROE for bundled electric operations of
12.50%) and an overall rate of return ("ROR") of 9.30% (a reduction from NPC's
last-authorized ROR for bundled electric operations of 10.02%). Public hearings
on NPC's general rate case began on February 4, 2002. Various parties have
intervened in NPC's general rate case including the Staff of the PUCN, the
Bureau of Consumer Protection from the Nevada Attorney General's office,
MGM/Mirage, and the Nevada Coalition Of Commercial Energy Consumers. The
reduction of NPC's revenue requirements proposed by the intervenors ranges from
$50 million to $107 million.
Nevada Power Company Deferred Energy Case (NPC)
On November 30, 2001, NPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 through September 30, 2001. This application was mandated by AB
369, which was enacted by the Nevada Legislature in April 2001. The application
seeks to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to
clear accumulated purchased fuel and power costs of $922 million and spread the
cost recovery over a not more than three-year period. It also seeks to
recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased
fuel and power costs. The total rate increase resulting from the DEAA would
amount to 21%. NPC has proposed an alternate plan in which full recovery of the
deferred balance would be amortized over a period greater than three years, but
not to exceed six years. Public hearings began March 4, 2002. Various parties
have intervened in NPC's deferred energy rate case including the Staff of the
PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's
office, MGM/Mirage, the Southern Nevada Water Authority, the Nevada Energy
Buyers Group, and the Nevada Coalition Of Commercial Energy Consumers. The
disallowance of NPC's deferred energy balance that is proposed by the
intervenors ranges from $85 million to $980 million.
Sierra Pacific Power Company General Rate Case (SPPC)
On November 30, 2001, SPPC filed an application with the PUCN seeking an
electric general rate increase. This application was mandated by AB 369, which
was enacted by the Nevada Legislature in April 2001. On February 28, 2002, SPPC
filed a certification to its general rate filing, updating costs and revenues
pursuant to Nevada regulations. In the certification filing, SPPC requested an
increase in its general rates charged to all classes of electric customers,
which were designed to produce an increase in annual electric
110
revenues of $15.9 million representing an overall 2.4% rate increase. The
application also seeks an ROE for SPPC's total electric operations of 12.25% (an
increase from SPPC's last authorized ROE for bundled electric operations of
12.0%) and an overall ROR of 9.42% (a reduction from SPPC's last authorized ROR
for bundled electric operations of 10%). Public hearings for SPPC's general rate
case are scheduled to begin on April 8, 2002. Various parties have intervened in
SPPC's general rate case including the Staff of the PUCN, the Bureau of Consumer
Protection from the Nevada Attorney General's office, and Barrick Goldstrike
Mines, among others. Intervenor testimony will not be filed until March 22,
2002.
Sierra Pacific Power Company Deferred Energy Case (SPPC)
On February 1, 2002, SPPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 and November 30, 2001. This application was mandated by AB 369.
The application seeks to establish a DEAA rate to clear accumulated purchased
fuel and power costs of $205 million and spread the cost recovery over a not
more than three-year period. It also seeks to recalculate the Base Tariff Energy
Rate to reflect anticipated ongoing purchased fuel and power costs. The total
rate increase resulting from the DEAA would amount to 9.8%. SPPC has proposed an
alternate plan in which full recovery of the deferred balance would be amortized
over a period greater than three years, but not to exceed six years. Public
hearings are scheduled to begin in April 2002. Various parties have intervened
in SPPC's deferred energy rate case including the Staff of the PUCN, the Bureau
of Consumer Protection from the Nevada Attorney General's office, and Barrick
Goldstrike Mines, among others. Intervenor testimony will not be filed until
April 22, 2002.
Finance Authority (NPC, SPPC)
On September 20, 2001, the PUCN approved the June 19, 2001 applications by
the Utilities for authority to issue long or short-term debt on either a secured
or unsecured basis in an aggregate amount not to exceed $200 million for NPC and
$100 million for SPPC through the end of 2002. NPC has issued all of its $200
million of authorized debt. SPPC has not issued any debt under this authority
and has the full amount of the $100 million of authorized debt available for
future issuances. On September 20, 2001, the PUCN also approved the Utilities'
June 19, 2001 applications to amend an order issued by the PUCN allowing each of
the Utilities to issue unsecured short-term promissory notes in an amount not to
exceed $250 million through the period ending December 31, 2001. In the
applications, the Utilities requested that the PUCN amend its previous order to
provide the Utilities with the flexibility to issue secured promissory notes in
addition to, or in lieu of, the authorized unsecured promissory notes.
On October 1, 2001, NPC and SPPC each filed an application with the PUCN
requesting authority to issue secured or unsecured promissory notes in aggregate
amounts not to exceed $250 million through December 31, 2004. On October 9,
2001, the Utilities filed amended applications reducing the time period to
December 31, 2003. On November 29, 2001, the PUCN issued a compliance order
approving the requests. Currently, NPC has $50 million and SPPC has $100 million
of short-term debt authority remaining from these PUCN authorizations.
Natural Gas Rate Increase (SPPC)
On June 29, 2001, SPPC filed with the PUCN a Purchase Gas Adjustment (PGA)
seeking recovery of $41.4 million in accumulated, unrecovered purchased gas
expenses, and an increase in the going-forward rate to $.71 per therm. Public
hearings were held on October 22 and 23, 2001. On November 5, 2001, the PUCN
granted SPPC's application and approved recovery of the entire $41.4 million
accumulated deferred balance over a three-year period and an increase in the
going-forward rate to $.6648 per therm. Any over or under-recovery of future
energy costs will be the subject of a future PGA application. SPPC will file its
next PGA on July 1, 2002.
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FERC Matters (NPC and SPPC)
- ---------------------------
Price Mitigation Plan
On June 19, 2001, the FERC adopted a price mitigation plan applicable to
spot market wholesale power sales in California and throughout the western
United States during the period June 20, 2001 through September 30, 2002. The
price mitigation plan establishes a mechanism with which to determine the
maximum amount that may be charged for power sold during this period. The intent
of the mitigation plan is to simulate the price that might be charged for
electricity sold under competitive market conditions. Sellers that do not wish
to establish rates on the basis of this price mitigation plan may propose
cost-of-service rates covering all of their generating units in the WSCC for the
duration of the mitigation plan. Although the Utilities are not able to predict
at this time the long-term effect that the FERC price mitigation and other
market developments plan may have on their results of operations, management
believes that, under certain market conditions, the FERC plan adversely affects
the availability of spot market power to the Utilities and reduces the price at
which the Utilities can sell power on the wholesale market. Another potential
result from these price mitigation measures could be the delay and/or
cancellation of proposed power plants throughout the western United States. If
these results occur, the long-term supply of energy could be reduced. Numerous
parties, including NPC and several northwest utilities, appealed the June 19 and
July 25, 2001 orders from the FERC to the District of Columbia Court of Appeals
on the basis that the price caps are unfair to electric customers who reside
outside of California. In a report to Congress on January 31, 2002, the FERC
said the price mitigation plan had little if any influence on prices at which
Western utilities were able to resell power. SPR is not persuaded by the FERC's
report and continues to believe that the FERC's price caps have negatively
impacted electric customers outside California. The parties to the appeal await
action by the Court.
Wholesale Sales Tariffs
On March 13, 2001, the Utilities each filed an application for an order
approving market-based rates. The market-based authority would apply to sales of
electric energy and capacity outside of the Utilities' control areas. On May 11,
2001, SPPC and NPC received approval for market-based rates subject to a
compliance order. SPPC's and NPC's compliance filing was accepted on August 10,
2001.
California Matters (SPPC)
- -------------------------
Rate Stabilization Plan
SPPC serves approximately 44,500 customers in California. On June 29, 2001,
SPPC filed with the CPUC a Rate Stabilization Plan, which includes two phases.
Phase One, which was also filed June 29, 2001, is an emergency electric rate
increase of $10.2 million annually or 26%. If granted, the typical residential
monthly electric bill for a customer using 650 kilowatt-hours would increase
from approximately $47.12 to $60.12. On August 14, 2001, a pre-hearing
conference was held, and a procedural order was established. On September
27,2001, the Administrative Law Judge issued an order stating that no interim or
emergency relief could be granted until the end of the "rate freeze" period
mandated by the California restructuring law for recovery of stranded costs. In
accordance with the judge's request, on October 26, 2001, SPPC filed an
amendment to its application declaring the rate freeze period to be over.
Phase Two, which is scheduled to be filed with the CPUC in April 2002, will
be a general rate case to recover costs for expenses other than fuel and
purchased power. SPPC will also ask the CPUC to reinstate the Energy Cost
Adjustment Clause, which would allow SPPC to file for periodic rate adjustments
to reflect its actual costs for fuel and purchased power. Phase Two will also
include a proposal pertaining to the termination of the 10% rate reduction
mandated by AB 1890. On December 5 and 11, 2001 hearings on Phase One were held
and on January 11, 2002, opening briefs were filed. Reply briefs were filed on
January 25, 2002. A proposed draft decision is expected by the end of March
2002. SPPC will file Phase Two on April 1, 2002.
112
NOTE 4. EARNINGS PER SHARE
The following table outlines the calculation for Diluted EPS. The
difference between Basic EPS and Diluted EPS is due to common stock equivalent
shares resulting from stock options, the employee stock purchase plan,
performance shares and a non-employee director stock plan. Common stock
equivalents were determined using the treasury stock method. Also see Note 7,
Common Stock and Other Paid-in Capital.
Year ended December 31,
--------------------------------------------
2001 2000 1999
------------ ------------ ------------
Basic EPS
Numerator ($000)
Income (loss) from continuing operations $ 29,866 $ (49,414) $ 48,210
Income from discontinued operations 1,022 9,634 3,540
Gain on disposal of water business 25,845 -- --
------------ ------------ ------------
Net income (loss) $ 56,733 $ (39,780) $ 51,750
============ ============ ============
Denominator
Weighted average number of shares outstanding 87,542,441 78,435,405 62,577,385
============ ============ ============
Per-Share Amounts:
Income (loss) from continuing operations $ 0.34 $ (0.63) $ 0.77
Income from discontinued operations 0.01 0.12 0.06
Gain on disposal of water business 0.30 -- --
------------ ------------ ------------
Net income (loss) $ 0.65 $ (0.51) $ 0.83
============ ============ ============
Diluted EPS
Numerator ($000)
Income (loss) from continuing operations $ 29,866 $ (49,414) $ 48,210
Income from discontinued operations 1,022 9,634 3,540
Gain on disposal of water business 25,845 -- --
------------ ------------ ------------
Net income (loss) $ 56,733 $ (39,780) $ 51,750
============ ============ ============
Denominator
Weighted average number of shares outstanding
before dilution 87,542,441 78,435,405 62,577,385
Stock options/1/ 14,021 5,645 20,447
Executive long term incentive plan- performance shares/1/ 43,693 35,393 26,118
Non-Employee Director stock plan/1/ 9,355 5,885 5,736
Employee stock purchase plan/1/ 2,862 2,807 1,790
------------ ------------ ------------
87,612,372 78,485,135 62,631,476
------------ ------------ ------------
Per-Share Amounts/1/:
Income (loss) from continuing operations $ 0.34 $ (0.63) $ 0.77
Income from discontinued operations 0.01 0.12 0.06
Gain on disposal of water business 0.30 -- --
------------ ------------ ------------
Net income (loss) $ 0.65 $ (0.51) $ 0.83
============ ============ ============
/1/ Because of a net loss for the year ended December 31, 2000, stock
equivalents would be anti-dilutive. Accordingly, Diluted EPS for that
period is computed using the weighted average number of shares
outstanding before dilution.
113
NOTE 5. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY
Investments in subsidiaries and other property consisted of (dollars in
thousands):
Sierra Pacific Resources
------------------------
December 31,
2001 2000
-------- --------
Investment in Pinon Pine, LLC $ 55,319 $ 58,049
Investment in TGTC 18,799 17,164
Investment in Sierra Touch America 9,917 2,675
Cash Value-Life Insurance 12,580 13,393
Acquisition Costs 220 12,451
Other Investments 32,057 31,330
-------- --------
$128,892 $135,062
======== ========
Nevada Power
------------
December 31,
2001 2000
-------- --------
Cash Value-Life Insurance $ 12,580 $ 13,393
Other 141 25
-------- --------
$ 12,721 $ 13,418
======== ========
Sierra Pacific Power
--------------------
December 31,
2001 2000
-------- --------
Investment in Pinon Pine, LLC $ 55,319 $ 58,049
Other 1,866 1,998
-------- --------
$ 57,185 $ 60,047
======== ========
SPPC, through its wholly owned subsidiaries, Pinon Pine Corp., Pinon Pine
Investment Co., and GPSF-B, owns Pinon Pine Company, L.L.C. (the "LLC"). The LLC
was formed to take advantage of federal income tax credits associated with the
alternative fuel (syngas) produced by the coal gasifier available under ss. 29
of the Internal Revenue Code. The entire project, which includes an LLC-owned
gasifier and an SPPC-owned power island and post-gasification facility to
partially cool and clean the syngas, is referred to collectively as the Pinon
Pine Power Project ("Pinon Pine"). Construction of Pinon Pine was completed in
June 1998.
Pinon Pine is a project co-funded by the Department of Energy (DOE) under
an agreement between SPPC and DOE that expired December 31, 2000. Through
December 31, 2001, the DOE funded $167 million for construction, operation, and
maintenance of the project. Included in the Consolidated Balance Sheets of SPR
and SPPC is the net book value of the gasifier and related assets, which is
approximately $105 million as of December 31, 2001, of which $50 million is
included in Utility Plant, and $55 million is included in Investments in
subsidiaries and other property.
114
To date, SPPC has not been successful in obtaining sustained operation
of the gasifier. SPPC has retained an independent engineering consulting firm,
to complete a comprehensive study of the Pinon Pine gasification plant by
mid-2002. The study will evaluate the potential modifications required to make
the facility operational and reliable using several technology scenarios. The
evaluation of each scenario will include an estimate of the additional capital
expenditures necessary for reliable operation of the facility, and the risks
associated with that technology.
Although not anticipated, if analysis of the study by SPPC's management
indicates there is no economically feasible use of the Pinon Pine assets, SPPC
intends to pursue recovery of Pinon Pine, net of salvage, as a regulatory asset.
The request for recovery would be based, in part, on the PUCN's approval of
Pinon Pine in an earlier resource plan. In that event, if SPPC is unsuccessful
in obtaining recovery, there could be a material adverse effect on SPPC's and
SPR's financial condition and results of operations.
NOTE 6. JOINTLY OWNED FACILITIES
At December 31, 2001, SPR (through its utility subsidiaries NPC and
SPPC) owned the following undivided interests in jointly owned electric utility
facilities:
% Owned Construction
by Accumulated Net Plant in Work in
Generating Facility Subsidiary Plant in Service Depreciation Service Progress Subsidiary
- ----------------------------------------------------------------------------------------------------------------------
Navajo Station 11.3 $225,748 $ 97,933 $127,815 $ 3,804 NPC
Mohave Facility 14.0 84,570 37,133 47,437 1,655 NPC
Reid Gardner No. 4 32.2 126,107 54,580 71,527 278 NPC
Valmy Station 50.0 281,768 126,370 155,398 21 SPPC
-------- -------- -------- -------
TOTAL $718,193 $316,016 $402,177 $ 5,758
======== ======== ======== =======
The above amounts for Navajo and Mohave include NPC's share of
transmission systems and general plant equipment and, in the case of Navajo,
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
facilities. NPC's share of operating expenses for these facilities is included
in the corresponding operating expenses in the Consolidated Statements of
Income.
The Mohave Generating Station is jointly owned by Southern California
Edison (56%), Los Angeles Department of Water and Power (20%), NPC (14%) and
Salt River Project (10%). According to the terms of the operating agreement, if
any of the participants default on their contractual obligations for a period of
six (6) months, thereafter the output of the station is reduced by the
defaulting participant's percentage of ownership. The non-defaulting
participants would then assume the station's reduced variable costs and ongoing
fixed operating costs in accordance with their respective ownership percentages.
The non-defaulting participants would submit the dispute or default to a board
of arbitrators, which would determine what remedies are necessary to resolve the
dispute or remedy the default. At December 31, 2001, none of the participants
had defaulted on their contractual obligations.
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 the accompanying Consolidated Statements of Income.
115
NOTE 7. COMMON STOCK AND OTHER PAID-IN CAPITAL
As of December 31, 2001, 3,508,039 shares of common stock were reserved
for issuance under the Common Stock Investment Plan (CSIP), Employees' Stock
Purchase Plan (ESPP), Non-Employee Director Stock Plan and Executive Long-Term
Incentive Plan (ELTIP). The ELTIP for key management employees allows for the
issuance of SPR's common shares to key employees through December 31, 2003. 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 and bonus stock. SPR also provides
an ESPP to all of its employees meeting minimum service requirements. Employees
can choose twice each year 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
Number 25.
As a part of the August 1, 1999, merger, the NPC ELTIP was terminated
and existing SPR plans were adopted by the surviving company.
On September 21, 1999, the Board of Directors of SPR (the "SPR Board")
declared a dividend distribution of one right (an "SPR Right") for each
outstanding share of SPR common stock to shareholders of record at the close of
business on October 31, 1999. By issuing the new SPR Rights, the SPR Board
extended the benefits and protections afforded to shareholders under the Rights
Agreement, dated as of October 31, 1989, which expired on October 31, 1999. Each
SPR Right, initially evidenced by and traded with the shares of SPR Common
Stock, entitles the registered holder (other than an "Acquiring Person" as
defined in the Rights Agreement) to purchase at an exercise price of $75.00,
$150.00 worth of common stock at its then-market value, subject to certain
conditions and approvals set forth in the Rights Agreement. If, at any time
while there is an Acquiring Person, SPR engages in a merger or other business
combination transaction or series of related transactions in which the Common
Stock is changed or exchanged or 50% or more of its assets or earning power is
transferred, each SPR Right (not previously voided by the occurrence of a
Flip-in Event, as described in the Rights Agreement) will entitle its holder to
purchase, at the SPR Right's then-current Exercise Price, common stock of such
Acquiring Person having a calculated value of twice the SPR Right's then-current
Exercise Price. The SPR Rights are not exercisable until the Distribution Date
and expire on October 31, 2009, unless previously redeemed by SPR. Following an
SPR Distribution Date, the SPR Rights will trade separately from the SPR Common
Stock and will be evidenced by separate certificates. Until an SPR Right is
exercised, the holder thereof will have no rights as a shareholder of SPR,
including, without limitation, the right to receive dividends. The purpose of
the plan is to help ensure that SPR's shareholders receive fair and equal
treatment in the event of any proposed hostile takeover of SPR.
On August 15, 2001, SPR completed a public offering of 23,575,000
shares of its common stock, yielding net proceeds of approximately $340 million,
all of which were contributed to NPC as an additional equity investment.
On November 16 and 21, 2001, SPR completed a public offering of
6,900,000 of its Corporate PIES, yielding net proceeds of approximately $345
million. Each Corporate PIES unit consists of a forward stock purchase contract
and a senior unsecured note issued by SPR with a face amount of $50. The senior
notes are pledged as collateral to secure each holder's obligation to purchase
shares of SPR common stock under the stock purchase contract. The senior note
may be released from the pledge arrangement if a holder opts to create Treasury
PIES by delivering a like principal amount of U.S. Treasury securities to the
Securities Intermediary in substitution for the senior notes.
116
Each stock purchase contract obligates the holder to purchase SPR
common stock on or before November 15, 2005, the Purchase Contract Settlement
Date. The number of shares each investor is entitled to receive will depend on
the average closing price of SPR common stock over a 20-day trading period prior
to the settlement. Prior to the Purchase Contract Settlement Date, holders of
Corporate PIES have the option to pay $50 per Corporate PIES to settle their
purchase contract obligations. If the holders do not elect to make a cash
payment, the proceeds from the remarketing of the senior notes will be used to
satisfy their purchase contract obligations.
The purchase contracts are forward transactions in SPR common stock.
Upon issuance, a liability for the present value of the purchase contract
adjustment payments, approximately $13.7 million, was recorded in Other deferred
credits, with a corresponding reduction to Other paid-in capital. See further
discussion regarding these senior notes and the purchase contract adjustment
payments at Note 9 - Long-Term Debt. Upon settlement of a purchase contract, SPR
will receive the stated amount of $50 on the purchase contract and will issue
the required number of shares of common stock. The stated amount received will
be credited to stockholders' equity and allocated between the Common stock and
Other paid-in capital accounts.
Prior to the issuance of common stock upon settlement of the purchase
contracts, SPR expects that the PIES will be reflected in SPR `s earnings per
share calculations using the treasury stock method. Under this method, the
number of shares of common stock used in calculating earnings per share is
deemed to be increased by the excess, if any, of the number of shares of common
stock issuable upon settlement of the purchase contracts over the number of
shares that could be purchased by SPR in the market at the average closing price
during the relevant period using the proceeds receivable upon settlement. As a
result, SPR expects there will be no dilutive effect on its earnings per share
except during periods when the average closing price per share of common stock
is above the threshold appreciation price.
The changes in common stock and additional paid-in capital for 2001,
2000, and 1999, are as follows (dollars in thousands):
Shares Issued Amount
------------------------------------ ------------------------------------
2001 2000 1999 2001 2000 1999
---------- ------ ---------- --------- ---------- ----------
Public Offering 23,575,000 - - $340,364 $ - $ -
Merger Exchange - - 78,414,560 - - 66,540
CSIP/DRP - 5,389 - - 237 -
ESPP and other 60,319 55,268 - 830 1,055 -
---------- ------ ---------- --------- ---------- ----------
23,635,319 60,657 78,414,560 $341,194 $ 1,292 $ 66,540
========== ====== ========== ========= ========== ==========
NOTE 8. PREFERRED STOCK AND PREFERRED TRUST SECURITIES
SPPC's preferred stock is superior to SPPC's common stock with respect
to dividend payments (which are cumulative) and liquidation rights.
The following table indicates the dollar amount and number of shares of
SPPC preferred stock outstanding at December 31 of each year:
117
Amount Shares Outstanding
------------------------ --------------------------
(Dollars in thousands) 2001 2000 2001 2000
------------------------ --------------------------
Preferred Stock
Not subject to mandatory redemption:
SPPC Class A Series I 50,000 50,000 2,000,000 2,000,000
------------------------ --------------------------
Total Preferred Stock $ 50,000 $ 50,000 2,000,000 2,000,000
======================== ==========================
The following table indicates the principal amount and number of shares of
NPC and SPPC preferred trust securities outstanding at December 31 of each year:
Amount Shares Outstanding
------------------------ --------------------------
(Dollars in thousands) 2001 2000 2001 2000
------------------------ --------------------------
Preferred Trust Securities
Subject to mandatory redemption:
Preferred Securities of Nevada Power Co
Capital I $ 118,872 $ 118,872 147,058 147,058
Preferred Securities of Nevada Power Co
Capital III 70,000 70,000 86,598 86,598
------------------------ --------------------------
Subtotal 188,872 188,872 233,656 233,656
Preferred Securities of Sierra Pacific
Power Company Capital I - 48,500 - 1,940,000
------------------------ --------------------------
Total Preferred Trust Securities $ 188,872 $ 237,372 233,656 2,173,656
======================== ==========================
SPR has issued neither preferred stock nor preferred trust securities.
Nevada Power Company
- --------------------
Preferred Trust Securities
On April 2, 1997, NVP Capital I (Trust), a wholly owned subsidiary of NPC,
issued 4,754,860 8.2% QUIPS at $25 per security. NPC owns all of the Series A
common securities, 147,058 shares issued by the Trust for $3.7 million. The
QUIPS and the common securities represent undivided beneficial ownership
interests in the assets of the Trust, a statutory business trust formed under
the laws of the state of Delaware. The existence of the Trust is for the sole
purpose of issuing the QUIPS and the common securities and using the proceeds
thereof to purchase from NPC its 8.2% Junior Subordinated Deferrable Interest
Debentures (QUIDS) due March 31, 2037, extendible to March 31, 2046, under
certain conditions, in a principal amount of $122.6 million. The sole asset of
the Trust is the QUIDS. Holders of the Series A QUIPS are entitled to receive
preferential cumulative cash distributions accruing from the date of original
issuance and payable quarterly on the last day of March, June, September and
December of each year. The Series A QUIPS are subject to mandatory redemption,
in whole or in part, upon repayment of the Series A QUIDS at maturity or their
earlier redemption in an amount equal to the amount of related Series A QUIDS
maturing or being redeemed. The QUIPS are redeemable at $25 per preferred
security plus accumulated and unpaid distributions thereon to the date of
redemption. NPC's obligations provide a full and unconditional guarantee of the
Trust's obligations under the QUIPS. Financial statements of the Trust are
consolidated with NPC's. Separate financial statements are not filed because the
Trust is wholly owned by NPC and essentially has no independent operations, and
NPC's guarantee of the Trust's obligations is full and unconditional. The $118.9
million in net proceeds was used for general corporate utility purposes and the
repayment of short-term debt.
118
In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of
Nevada Power Company, issued 2,800,000, 7 3/4% Cumulative Quarterly Trust Issued
Preferred Securities at $25 per security. NPC owns the entire common securities,
86,598 shares issued by the Trust for $2.2 million. The Trust Issued Preferred
Securities and the common securities represent undivided beneficial ownership
interests in the assets of the Trust, a statutory business trust formed under
the laws of the state of Delaware. The existence of the Trust is for the sole
purpose of issuing the Trust Issued Preferred Securities and the common
securities and using the proceeds thereof to purchase from NPC its 7 3/4% Junior
Subordinated Deferrable Interest Debentures due September 30, 2038, extendible
to September 30, 2047, under certain conditions, in a principal amount of $72.2
million. The sole asset of the Trust is the deferrable interest debentures.
Holders of the Trust Issued Preferred Securities are entitled to receive
preferential cumulative cash distributions accruing from the date of original
issuance and payable quarterly on the last day of March, June, September and
December of each year. The Trust Issued Preferred Securities are subject to
mandatory redemption, in whole or in part, upon repayment of the deferrable
interest debentures at maturity or their earlier redemption in an amount equal
to the amount of related deferrable interest debentures maturing or being
redeemed. The Trust Issued Preferred Securities are redeemable at $25 per
preferred security plus accumulated and unpaid distributions thereon to the date
of redemption. NPC's obligations provide a full and unconditional guarantee of
the Trust's obligations under the Trust Issued Preferred Securities. Financial
statements of the Trust are consolidated with NPC's. Separate financial
statements are not filed because the Trust is wholly owned by NPC and
essentially has no independent operations, and NPC's guarantee of the Trust's
obligations is full and unconditional. The $70 million in net proceeds was used
for general corporate utility purposes including the repayment of short-term
debt.
Preferred Stock
On July 23, 1999, NPC redeemed the 4.7%, 5.2% and 5.4% Series
Redeemable Cumulative Preferred Stock. The total par value and premium was $3.5
million and was paid in accordance with the merger agreement with Sierra Pacific
Resources.
Sierra Pacific Power Company
- ----------------------------
Preferred Trust Securities
On July 29, 1996, Sierra Power Capital I (the Trust), a wholly owned
subsidiary of SPPC, issued $48.5 million (1,940,000 shares) of 8.60% Trust
Originated Preferred Securities (the Preferred Securities). SPPC owns all the
common securities of the Trust; 60,000 shares totaling $1.5 million (Common
Securities). The Preferred Securities and the Common Securities (the Trust
Securities) represent undivided beneficial ownership interests in the assets of
the Trust. The existence of the Trust is for the sole purpose of issuing the
Trust Securities and using the proceeds thereof to purchase from SPPC its 8.60%
Junior Subordinated Debentures due July 30, 2036, in a principal amount of $50
million. The sole asset of the Trust is SPPC's junior subordinated debentures.
SPPC's obligations provide a full and unconditional guarantee of the Trust's
obligations under the Preferred Securities.
On November 29, 2001 SPPC redeemed all of the outstanding 8.60% Trust
Originated Preferred Securities of its wholly owned subsidiary, Sierra Pacific
Power Capital Trust 1, at a price of $25.00 per preferred security. Financial
statements of the Trust are consolidated with SPPC's. Separate financial
statements are not filed because the Trust is wholly owned by SPPC and
essentially has no independent operation, and SPPC's guarantee of the Trust's
obligations is full and unconditional.
119
Preferred Stock
SPPC's Restated Articles of Incorporation, as amended on August 19,
1992, authorize an aggregate total of 11,780,500 shares of preferred stock at
any given time.
On November 1, 1999, SPPC paid $23.5 million, par value and premium, to
redeem Series A, $2.44 Dividend (4.88%), Series B, $2.36 Dividend (4.72%) and
Series C, $3.90 Dividend (7.8%).
On February 15, 2001, SPPC received consents from the holders of a
majority of its preferred stock to increase the amount of unsecured indebtedness
that SPPC may issue. Under SPPC's Restated Articles of Incorporation, SPPC
cannot, without the consent of a majority of the total number of votes which may
be cast by the holders of SPPC's preferred stock, issue unsecured debt
securities with maturities of greater than 12 months for any purpose (other than
refunding outstanding unsecured debt or retiring outstanding shares of preferred
stock) if such unsecured indebtedness would exceed 20% of the aggregate of (1)
the total principal amount of all bonds and other securities representing
secured indebtedness then outstanding and (2) the total capital and surplus of
SPPC then stated on its books. As of September 30, 2000, prior to the consent
solicitation, SPPC could issue approximately $14 million in additional unsecured
debt under this limitation. Pursuant to the consent solicitation, SPPC received
the consent of the holders of a majority of its preferred stock to issue up to
$400 million in long-term unsecured indebtedness in excess of the present
limitation. As of December 31, 2001, SPPC would have been able to issue
approximately $634 million of additional unsecured indebtedness. Upon receipt of
the required number of consents, SPPC paid a participation premium in the amount
of $.50 per share consented to each holder of shares of preferred stock whose
valid, unrevoked consent was received prior to the specified return date. The
aggregate amount of the participation premium paid was $.9 million. The only
series of preferred stock of SPPC currently outstanding is its Class A, Series 1
Preferred Stock, of which 2 million shares are outstanding.
NOTE 9. LONG-TERM DEBT
Substantially all utility plant is subject to the liens of NPC's and
SPPC's indentures under which their first mortgage bonds and General and
Refunding Mortgage bonds are issued.
Nevada Power Company
On April 20, 2000, NPC utilized a $100 million capital contribution
from SPR to retire $85 million of NPC's First Mortgage Bonds that matured on May
1, 2000, and to reduce outstanding commercial paper balances under NPC's
commercial paper program that was established in July 1999.
On June 22, 2000, Clark County, Nevada issued for NPC's benefit $100
million Industrial Development Refunding Revenue Bonds, Series 2000A, due June
1, 2020. The interest rate is currently being determined by a Dutch Auction
based on an auction period of seven days. The Series A bonds were issued to
refund $100 million of Clark County's 7.80% Industrial Development Revenue Bonds
Series 1990 on June 30, 2000.
On July 28, 2000, Clark County, Nevada issued for NPC's benefit $15
million Pollution Control Refunding Revenue Bonds, Series 2000B, due October 1,
2009. The interest rate is currently being determined by a Dutch Auction based
on an auction period of seven days. The Series B bonds were issued to refund a
like principal amount of Clark County's 7.80% Pollution Control Revenue Bonds
Series 1989 on October 2, 2000.
The method of determining the interest rate on the Series A and Series
B Bonds may be converted from time to time in accordance with the related
Indenture so that such bonds would, thereafter, bear interest at a daily,
weekly, flexible, term or auction rate. Both Series A and Series B Bonds are
insured by AMBAC Assurance Corporation ("AMBAC"). On August 3, 2001, NPC issued
$115 million of its Series BB and Series
120
CC First Mortgage Bonds to AMBAC to secure NPC's reimbursement obligations under
the Series 2000A and 2000B Clark County Bonds insurance agreements.
On May 24, 2001, NPC issued $350 million of its 8.25% General and
Refunding Mortgage Bonds, Series A, due June 1, 2011. The bonds were issued with
registration rights under and secured by a General and Refunding Mortgage
Indenture dated as of May 1, 2001 that is subject to the prior lien of NPC's
Indenture of Mortgage dated as of October 1, 1953. The proceeds of the issuance
were used to refinance or discharge outstanding indebtedness including
commercial paper, short-term debt, and current maturities of long-term debt. On
January 29, 2002, NPC successfully completed the exchange of these bonds for
identical bonds, registered under the Securities Act of 1933.
On June 12, 2001, $150 million of NPC's floating rate notes matured and
were paid in full. The floating rate notes were issued on June 9, 2000, and the
net proceeds of the $150 million issue were used to redeem $100 million of
floating rate notes on July 14, 2000, and to reduce NPC's commercial paper
outstanding under its commercial paper program.
On August 20, 2001, $100 million of NPC's floating rate notes matured
and were paid in full. The floating rate notes were issued August 18, 2000, and
the net proceeds of the $100 million issue were used to reduce NPC's commercial
paper outstanding under its commercial paper program.
On September 20, 2001 and October 15, 2001, NPC issued an aggregate
total of $210 million of 6% unsecured notes due September 15, 2003. Interest on
the notes is payable on March 15 and September 15 of each year. These notes are
not entitled to any sinking fund and are non-callable. The proceeds of the
issuance were used to refinance or discharge outstanding indebtedness including
commercial paper, short-term debt, and current maturities of long-term debt.
On October 18, 2001, NPC issued $140 million of its General and
Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003. The
proceeds of the issuance were used to refinance or discharge outstanding
indebtedness including commercial paper, short-term debt, and current maturities
of long-term debt.
Sierra Pacific Power Company
On April 27, 2001, Washoe County, Nevada issued for SPPC's benefit $80
million of Water Facilities Refunding Revenue Bonds, Series 2001, due March 1,
2036. The bonds bear interest at a term rate of 5.75% per annum from their date
of issuance to April 30, 2003. Beginning May 1, 2003, the method of determining
the interest rate on the bonds may be converted from time to time in accordance
with the related Indenture so that such bonds would, thereafter, bear interest
at a daily, weekly, flexible, term or auction rate. The bonds were issued to
refund $80 million of Washoe County variable rate Water Facilities Revenue Bonds
(Sierra Pacific Power Company Project) Series 1990 on April 30, 2001. SPPC's
obligations in respect of the Series 1990 bonds had been supported by a letter
of credit that was terminated in connection with the redemption of those bonds.
On June 11, 2001, SPPC completed the sale of its water business assets including
the Project financed by the sale of the bonds. Although SPPC no longer owns the
Project, SPPC will continue to bear the obligations and payments for the bonds
under the terms of the Financing Agreement dated as of March 1, 2001, between
SPPC and Washoe County, Nevada.
On May 24, 2001, SPPC issued $320 million of its 8.00% General and
Refunding Mortgage Bonds, Series A, due June 1, 2008. The bonds were issued with
registration rights under and secured by a General and Refunding Mortgage
Indenture dated as of May 1, 2001 that is subject to the prior lien of SPPC's
Indenture of Mortgage dated as of December 1, 1940. The proceeds of the issuance
were used to refinance or discharge outstanding indebtedness including
commercial paper, short-term debt, and current maturities of long-term debt. On
January 29, 2002, SPPC successfully completed the exchange of these bonds for
identical bonds, registered under the Securities Act of 1933.
121
On June 12, 2001, $200 million of SPPC's floating rate notes matured
and were paid in full. The floating rate notes were issued on June 9, 2000, and
the net proceeds of the $200 million issue were used to redeem $100 million of
floating rate notes on July 14, and the remaining proceeds were used to reduce
the amount of SPPC's commercial paper outstanding under the program established
in July 1999.
On December 17, 2001, $17 million of SPPC's MTN Series D matured and
were paid in full.
Sierra Pacific Resources
On March 31, 2000, $10 million of SPR's Series E senior notes matured
and were paid in full.
On April 20, 2000, SPR issued an aggregate of $300 million floating
rate notes, $200 million of which matures on April 20, 2003 and the remaining
$100 million of which matures on April 20, 2002. Interest on the notes is
payable quarterly. The interest rate on the notes for each interest period is a
floating rate, subject to adjustment every three months, equal to the LIBOR for
three-month U.S. dollar deposits plus a spread of 0.60% for the notes maturing
in 2003, and a spread of 0.65% for the notes maturing in 2002.These notes are
not entitled to any sinking fund. The notes due 2002 will be redeemable in
whole, without premium, at the option of SPR beginning April 20, 2001, and on
each interest payment date thereafter. The net proceeds of the $200 million
issue were used to retire an equal amount of commercial paper of SPR issued
under the line of credit established in July 1999 that was used as temporary
funding for the cash portion of the NPC merger consideration. The net proceeds
of the $100 million issue were used to make a capital contribution to NPC. On
September 26, 2000, SPR entered into a forward swap relating to its $200 million
floating rate notes that will mature on April 20, 2003, effectively locking in a
LIBOR rate of 6.655%, which will result in an interest rate of 7.255% on the
notes until their maturity. This transaction became effective on October 20,
2000.
On May 9, 2000, SPR issued $300 million of its 8.75% Notes due 2005.
Interest on the notes is payable semi-annually. The notes are not subject to any
sinking fund and are redeemable in whole or in part at any time upon payment of
the principal amount of the notes being redeemed, plus accrued interest and a
make-whole premium. The net proceeds from the issuance of these notes were used
to retire an equal amount of commercial paper issued by SPR under its commercial
paper program that was established in July 1999 and was cancelled in June 2001.
On November 16 and 21, 2001, SPR issued an aggregate of $345 million
senior unsecured notes in connection with the public offering of 6,900,000 of
its Corporate PIES. Each Corporate PIES unit consists of a forward stock
purchase contract and a senior unsecured note issued by SPR with a face amount
of $50. The senior notes are pledged as collateral to secure each holder's
obligation to purchase shares of SPR common stock under the stock purchase
contract. The senior note may be released from the pledge arrangement if a
holder opts to create Treasury PIES by delivering a like principal amount of
U.S. Treasury securities to the Securities Intermediary in substitution for the
senior notes.
Each stock purchase contract obligates the holder to purchase SPR
common stock on or before November 15, 2005, the Purchase Contract Settlement
Date. The number of shares each investor is entitled to receive will depend on
the average closing price of SPR common stock over a 20-day trading period prior
to the settlement. See further discussion regarding the forward stock purchase
contract at Note 7 Common Stock And Other Paid-In-Capital.
Each holder of Corporate PIES is entitled to receive quarterly payments
consisting of purchase contract adjustment payments and interest on the senior
unsecured notes. The Corporate PIES have a combined rate of 9.0%, which is
comprised of the coupon on the senior note of 7.93% and the stated rate of the
purchase contract adjustment payments of 1.07%. Interest on the senior unsecured
notes began to accrue on November 16, 2001, and quarterly interest payments will
be made each quarter beginning with the first payment, which was made on
122
February 15, 2002. All senior unsecured notes will be remarketed beginning on
August 10, 2005, up to and including November 1, 2005, and, if necessary, on
November 9, 2005, unless holders of senior notes that are not part of a
Corporate PIES elect not to have their senior notes remarketed. Upon
remarketing, the interest rate will be reset and the senior notes will accrue
interest at the reset rate after the remarketing settlement date. Prior to the
Purchase Contract Settlement Date, holders of Corporate PIES have the option to
pay $50 per Corporate PIES to settle their purchase contract obligations. If the
holders do not elect to make a cash payment, the proceeds from the remarketing
of the senior notes will be used to satisfy their purchase contract obligations.
If any senior notes remain outstanding after the Purchase Contract Settlement
Date, SPR will pay interest payments on those senior notes until their maturity
on November 15, 2007.
Purchase contract adjustment payments will accrue from November 16,
2001. Holders received the first quarterly purchase contract adjustment payments
of $0.1323 per unit ($913,000 in aggregate) on February 15, 2002, and will
receive payments of $0.1338 per unit ($923,000 in aggregate) for each subsequent
quarter. Upon issuance, a liability for the present value of the purchase
contract adjustment payments, approximately $13.7 million, was recorded in Other
Deferred Credits, with a corresponding reduction to Other Paid-in-Capital.
NPC's, SPPC's and SPR's aggregate annual amount of maturities for
long-term debt for the next five years is shown below (in thousands of dollars):
SPR Holding Co. SPR
NPC SPPC and Other Subs. Consolidated
------------ ------------- --------------- ------------
2002 $ 19,380 $ 2,630 $ 100,000 $ 122,010
2003 350,000 20,632 200,000 570,632
2004 130,000 2,621 - 132,621
2005 - 2,622 300,000 302,622
2006 - 52,629 - 52,629
------------ ------------- -------------- -------------
Subtotal 499,380 81,134 600,000 1,180,514
Thereafter 1,127,967 844,566 345,068 2,317,601
------------ ------------- -------------- -------------
Total $ 1,627,347 $ 925,700 $ 945,068 $ 3,498,115
============ ============= ============== =============
123
NOTE 10. TAXES
Nevada Power Company
The following reflects the composition of taxes on income (in thousands
of dollars):
2001 2000 1999
---------- ----------- ----------
As Reflected in Statement of Income:
Federal income taxes $ 18,715 $ (12,162) $ 19,943
State income taxes (940) - -
----------- ----------- ----------
Operating Income 17,775 (12,162) 19,943
Other income - net 15,008 2,776 1,270
----------- ----------- ----------
Total $ 32,783 $ (9,386) $ 21,213
=========== =========== ==========
The total income tax provisions differ from amounts computed by
applying the federal statutory tax rate to income before income taxes for the
following reasons (in thousands of dollars):
2001 2000 1999
------------ ----------- -----------
Income before preferred dividend requirements $ 63,405 $ (7,928) $ 38,787
Total income tax expense 32,783 (9,386) 21,213
------------ ----------- -----------
96,188 (17,314) 60,000
Statutory tax rate 35% 35% 35%
------------ ----------- -----------
Expected income tax expense 33,666 (6,060) 21,000
Depreciation related to difference in costs basis for tax purposes 1,431 1,431 1,431
Allowance for funds used during construction - equity 383 300 300
Tax benefit from the disposition of assets - - -
State taxes (net of federal benefit) (611) - -
ITC amortization (1,630) (1,460) (1,460)
Other - net (456) (3,597) (58)
------------ ----------- -----------
$ 32,783 $ (9,386) $ 21,213
============ =========== ===========
Effective tax rate 34.1% 54.2% 35.5%
============ =========== ===========
124
The net accumulated deferred federal income tax liability consists of
accumulated deferred federal income tax liabilities less related accumulated
deferred federal income tax assets, as shown (in thousands of dollars):
2001 2000
----------- -----------
Deferred Federal Income Tax Liabilities:
Allowance for funds used during construction - debt $ 7,659 $ 6,067
Bond redemptions 5,460 5,683
Excess of tax depreciation over book depreciation 212,969 197,248
Severance programs 1,982 1,982
Tax benefits flowed through to customer 113,647 114,097
Deferred energy 343,023 -
Other - net 1,943 (1,016)
----------- -----------
686,683 324,061
----------- -----------
Deferred Federal Income Tax Assets:
Avoided interest capitalized 11,217 9,584
Employee benefit plans 8,555 3,536
Reserve for bad debt 10,801 4,062
Contributions in aid of construction and customer advances 69,232 63,953
Gross-ups received on contributions in aid of construction and customer advances 6,514 4,108
Excess deferred income taxes 5,859 6,358
Unamortized investment tax credit 13,255 13,550
Other - net (5,414) 2,157
----------- -----------
120,019 107,308
----------- -----------
Total $ 566,664 $ 216,753
=========== ===========
NPC's balance sheets contain a net regulatory asset of $94.4 million at
year-end 2001 and $94 million at year-end 2000. The net regulatory asset
consists of future revenue to be received from customers (a regulatory asset) of
$113.6 million at year-end 2001 and $114 million at year-end 2000, due to
flow-through of the tax benefits of temporary differences. Offset against this
amount are future revenues to be refunded to customers (a regulatory liability),
consisting of $5.9 million at year-end 2001 and $6.4 million at year-end 2000
due to temporary differences for liberalized depreciation at rates in excess of
current tax rates, and $13.3 million at year-end 2001 and $13.6 million at
year-end 2000 due to 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. In addition, certain
items of deferred taxes represent positive cash flows to NPC. These items reduce
rate base and, therefore, are benefits passed through to customers. However,
because NPC had a net operating loss for tax purposes in 2001, some of this
benefit could not be utilized (i.e., deferred energy).
125
Sierra Pacific Power Company
The following reflects the composition of taxes on income (in thousands
of dollars):
2001 2000 1999
----------- ----------- -----------
As Reflected in Statement of Income
Federal income taxes $ 10,731 $ (1,118) $ 32,982
State income taxes (2,224) 446 888
----------- ----------- -----------
Operating Income 8,507 (672) 33,870
Other income - net 1,753 (586) (324)
----------- ----------- ----------
Total $ 10,260 $ (1,258) $ 33,546
=========== =========== ==========
The total income tax provisions differ from amounts computed by
applying the federal statutory tax rate to income before income taxes for the
following reasons (in thousands of dollars):
2001 2000 1999
----------- ---------- -----------
Income before preferred dividend requirements $ 22,743 $ (4,077) $ 64,615
Total income tax expense 10,260 (1,258) 33,546
----------- ---------- ----------
33,003 (5,335) 98,161
Statutory tax rate 35% 35% 35%
----------- ---------- ----------
Expected income tax expense 11,551 (1,867) 34,356
Depreciation related to difference in costs basis for tax purposes 1,513 1,531 1,408
Allowance for funds used during construction - equity (298) (149) 386
Tax benefit from the disposition of assets (111) (175) (442)
ITC amortization (1,824) (1,824) (1,981)
State taxes (net of federal benefit) (1,446) 290 577
Other - net 875 936 (758)
----------- ---------- -----------
$ 10,260 $ (1,258) $ 33,546
=========== ========== ===========
Effective tax rate 31.1% 23.6% 34.2%
=========== =========== ===========
The net accumulated deferred federal income tax liability consists of
accumulated deferred federal income tax liabilities less related accumulated
deferred federal income tax assets, as shown (in thousands of dollars):
126
2001 2000
----------- -----------
Deferred Federal Income Tax Liabilities:
Allowance for funds used during construction - debt $ 4,837 $ 7,399
Bond redemptions 6,048 5,732
Excess of tax depreciation over book depreciation 188,389 176,125
Severance programs 3,317 3,465
Tax benefits flowed through to customer 63,410 65,471
Deferred energy 87,790 5,729
Other 4,132 6,366
----------- -----------
357,923 270,287
----------- -----------
Deferred Federal Income Tax Assets:
Avoided interest capitalized 12,444 11,313
Employee benefit plans 3,451 3,789
Reserve for bad debt 2,960 388
Contributions in aid of construction and customer advances 35,163 33,979
Gross-ups received on contributions in aid of construction and customer advances 5,462 5,059
Excess deferred income taxes 12,797 14,494
Unamortized investment tax credit 17,452 18,434
Other 1,871 3,725
----------- -----------
91,600 91,181
----------- -----------
Accumulated Deferred Federal Income Taxes $ 266,323 $ 179,106
=========== ===========
SPPC's balance sheets contain a net regulatory asset of $33.1 million
at year-end 2001 and $32.6 million at year-end 2000. The net regulatory asset
consists of future revenue to be received from customers (a regulatory asset) of
$63.4 million at year-end 2001 and $65.5 million at year-end 2000, due to
flow-through of the tax benefits of temporary differences. Offset against this
amount are future revenues to be refunded to customers (a regulatory liability),
consisting of $12.8 million at year-end 2001 and $14.5 million at year-end 2000,
due to temporary differences for liberalized depreciation at rates in excess of
current tax rates, and $17.5 million at year-end 2001 and $18.4 million at
year-end 2000 due to 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. In addition, certain
items of deferred taxes represent positive cash flows to SPPC. These items
reduce rate base and, therefore, are benefits passed through to customers.
However, because SPPC had a net operating loss for tax purposes in 2001, some of
this benefit could not be utilized (i.e., deferred energy).
Sierra Pacific Resources
The following reflects the composition of taxes on income (in thousands
of dollars):
2001 2000 1999
------------ ------------ -----------
As Reflected in Statement of Income:
Federal income taxes $ 1,934 $ (31,468) $ 24,410
State income taxes (3,164) 446 888
------------ ------------ -----------
Operating Income (1,230) (31,022) 25,298
Other income - net 16,761 2,190 946
------------ ------------ -----------
Total $ 15,531 $ (28,832) $ 26,244
============ ============ ===========
127
The total income tax provisions differ from amounts computed by
applying the federal statutory tax rate to income before income taxes for the
following reasons (in thousands of dollars):
2001 2000 1999
------------ ---------- ----------
Income before preferred dividend requirements $ 33,566 $ (45,915) $ 50,410
Total income tax expense (benefit) 15,531 (28,832) 26,244
------------ ---------- ---------
49,097 (74,747) 76,654
Statutory tax rate 35% 35% 35%
------------ ---------- ---------
Expected income tax expense (benefit) 17,184 (26,161) 26,829
Depreciation related to difference in costs basis for tax purposes 2,944 2,962 2,839
Allowance for funds used during construction - equity 85 151 686
Tax benefit from the disposition of assets (111) (175) (442)
ITC amortization (3,454) (1,824) (1,981)
State taxes (net of federal benefit) (2,057) (1,170) (883)
Other - net 940 (2,615) (804)
------------ ---------- ---------
$ 15,531 $ (28,832) $ 26,244
============ ========== =========
Effective tax rate 31.6% 38.6% 34.2%
=========== ========= =========
The net accumulated deferred federal income tax liability consists of
accumulated deferred federal income tax liabilities less related accumulated
deferred federal income tax assets, as shown (in thousands of dollars):
2001 2000
------------ ----------
Deferred Federal Income Tax Liabilities:
Allowance for funds used during construction - debt $ 12,496 $ 13,466
Bond redemptions 11,508 11,415
Excess of tax depreciation over book depreciation 401,358 373,373
Severance programs 5,299 5,447
Tax benefits flowed through to customer 177,057 179,568
Deferred energy 430,813 5,729
Other 16,558 5,350
------------ -----------
1,055,089 594,348
------------ -----------
Deferred Federal Income Tax Assets:
Avoided interest capitalized 23,661 20,897
Employee benefit plans 12,006 7,325
Reserve for bad debt 13,761 4,450
Contributions in aid of construction and customer advances 104,395 97,932
Gross-ups received on contribution in aid of construction and customer advances 11,976 9,167
Excess deferred income taxes 18,656 20,852
Unamortized investment tax credit 30,707 31,984
Other (3,543) (4,569)
------------ -----------
211,619 188,038
------------ -----------
Total $ 843,470 $ 406,310
============ ===========
SPR's balance sheets contain a net regulatory asset of $127.7 million
at year-end 2001 and $126.7 million at year-end 2000. The net regulatory asset
consists of future revenue to be received from customers (a regulatory asset) of
$177.1 million at year-end 2001 and $179.6 million at year-end 2000, due to
flow-through of the tax benefits of temporary differences. Offset against these
amounts are future revenues to be refunded to customers (a regulatory
liability), consisting of $18.7 million at year-end 2001 and $20.9 million at
128
year-end 2000, due to temporary differences for liberalized depreciation at
rates in excess of current tax rates, and $30.7 million at year-end 2001 and $32
million at year-end 2000 due to 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. In
addition, certain items of deferred taxes represent positive cash flows to SPR.
These items reduce rate base and, therefore, are benefits passed through to
customers. However, because SPR had a net operating loss for tax purposes in
2001, some of this benefit could not be utilized (i.e., deferred energy).
NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The December 31, 2001, carrying amount for 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, 2001, is estimated to be 1.56 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 $851.2 million at December 31,
2000. The estimated fair value of NPC's preferred trust securities is $181.5
million at December 31, 2001. The fair value of NPC's preferred securities was
estimated to be $186.3 million at December 31, 2000.
The total fair value of SPPC's consolidated long-term debt at December
31, 2001, is estimated to be $946.5 million (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 $587.4 million as of December
31, 2000. SPPC's preferred trust securities were redeemed on November 29, 2001.
The fair value of SPPC's preferred trust securities was estimated to be $48.5
million at December 31, 2000.
The total fair value of SPR's consolidated long-term debt at December
31, 2001, is estimated to be $3.386 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 $2.052 billion as of December
31, 2000. The estimated fair value of SPR's consolidated preferred trust
securities is $181.5 million at December 31, 2001. The fair value of SPR's
consolidated preferred trust securities was estimated to be $234.8 million at
December 31, 2000.
NOTE 12. SHORT-TERM BORROWINGS
SPR
On January 16, 2001, SPR paid off its commercial paper balance of $4
million. SPR cancelled its commercial paper program as of June 12, 2001.
On November 29, 2001, SPR put into place a $75 million unsecured
revolving credit facility that may be used for working capital and general
corporate purposes. This facility will expire on November 28, 2002. As of
December 31, 2001 SPR had not drawn on this facility and had no outstanding
balance.
129
NPC
On November 29, 2001, NPC put into place a $200 million unsecured
revolving credit facility that may be used for working capital and general
corporate purposes, including commercial paper backup. This new credit facility
requires NPC to issue General and Refunding Mortgage Bonds to secure this credit
facility in the event of a decline in NPC's senior unsecured debt rating. This
facility will expire on November 28, 2002.
On December 17, 2001, $100 million of NPC's floating rate notes matured
and were paid in full.
On December 31, 2001, NPC had a commercial paper balance outstanding of
$130.5 million with a weighted average interest rate of 2.85%, and remaining
capacity to issue an additional $69.5 million under its commercial paper
program. NPC sustained its A2/P2 ratings by Standard and Poor's and Moody's,
respectively.
SPPC
On November 29, 2001, SPPC put into place a $150 million unsecured
revolving credit facility that may be used for working capital and general
corporate purposes, including commercial paper backup. This new credit facility
requires SPPC to issue General and Refunding Mortgage Bonds to secure this
credit facility in the event of a decline in SPPC's senior unsecured debt
rating. This facility will expire on November 28, 2002.
On December 31, 2001, SPPC had a commercial paper balance outstanding
of $46.5 million with a weighted average interest rate of 2.77%, and remaining
capacity to issue an additional $103.5 million under its commercial paper
program. SPPC sustained its A2/P2 ratings by Standard and Poor's and Moody's,
respectively.
NOTE 13. DIVIDEND RESTRICTIONS
SPR's primary source of funds for the payment of dividends to its
stockholders is dividends paid by the Utilities on their common stock, all of
which is owned by SPR. Accordingly, SPR's ability to pay dividends is dependent
upon the ability of the Utilities to pay dividends on their common stock. The
Restated Articles of Incorporation of the Utilities, the indentures relating to
the various series of their First Mortgage Bonds, and the bank credit agreements
of SPR and the Utilities contain restrictions as to the payment of dividends on
their common stock and as to the purchase, redemption or retirement of their
capital stock.
130
NOTE 14. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS
Pension and other postretirement benefit plans: 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 table provides a reconciliation of
benefit obligations, plan assets and the funded status of the plans. This
reconciliation is based on a September 30 measurement date and reflects the
acquisition of SPPC by NPC during 1999 under purchase accounting:
Other Postretirement
Pension Benefits Benefits
------------------------------- ----------------------------
2001 2000 2001 2000
------------------------------ ----------------------------
Change in benefit obligations
Benefit obligation, beginning of year $ 348,135 $ 348,470 $ 77,790 $ 77,987
Service cost 13,494 11,907 1,922 1,775
Interest cost 27,742 26,469 6,358 5,829
Participant contributions - - 466 300
Plan amendment and special termination 476 498 - -
Actuarial loss (gain) 6,864 (8,922) (5,201) (4,101)
Special Termination Benefits 394 - - -
Acquisitions and divestiture - - (1,231) -
Benefits paid (36,428) (30,287) (4,661) (4,000)
------------- ------------- ------------ ------------
Benefit obligation, end of year $ 360,677 $ 348,135 $ 75,443 $ 77,790
============= ============= ============ ============
Change in plan assets
Fair value of plan assets, beginning of year $ 349,153 $ 326,708 $ 81,900 $ 66,688
Actual return on plan assets (39,320) 51,136 (15,797) 17,377
Company contributions 1,900 1,596 730 1,535
Participant contributions - - 466 300
Acquistion and divestiture - - (1,231) -
Benefits paid (36,428) (30,287) (4,661) (4,000)
------------- ------------- ------------ ------------
Fair value of plan assets, end of year $ 275,305 $ 349,153 $ 61,407 $ 81,900
============= ============= ============ ============
Funded Status, end of year $ (85,373) $ 1,018 $ (14,036) $ 4,110
Unrecognized net actuarial (gains) losses 61,750 (13,526) (5,365) (22,696)
Unrecognized prior service cost 10,366 11,561 - -
Unrecognized net transition obligation - - 10,280 11,248
Contributions made in 4th quarter 11,917 270 - -
------------- ------------- ------------ ------------
Accrued pension and postretirement
benefit obligations $ (1,340) $ (677) $ (9,121) $ (7,338)
============= ============= ============ ============
131
Amounts for pension and postretirement benefits recognized in the
consolidated balance sheets consist of the following:
Pension Benefits Benefits
------------------------- -------------------------
2001 2000 2001 2000
------------------------- -------------------------
Prepaid pension asset $ 14,051 $ 13,939 N/A N/A
Accrued benefit liability (15,391) (14,616) $ (9,121) $ (7,338)
Intangible asset - - N/A N/A
Accumulated other comprehensive income 1,395 1,395 N/A N/A
Additional minimum liability (1,395) (1,395) N/A N/A
----------- ----------- ----------- -----------
Net amount recognized $ (1,340) $ (677) $ (9,121) $ (7,338)
=========== =========== =========== ===========
The weighted-average actuarial assumptions as of the measurement date
were as follows:
Other Postretirement
Pension Benefits Benefits
---------------------------- ------------------------------
2001 2000 1999 2001 2000 1999
---------------------------- ------------------------------
Discount rate 7.50% 8.00% 7.50% 7.50% 8.00% 7.50%
Expected return on plan assets 8.50% 8.50% 8.50% 8.50% 8.50% 8.50%
Rate of compensation increase 4.50% 4.50% 4.50% N/A N/A N/A
SPR has assumed a health care cost trend rate of 6% for 2001 and all
future years.
132
Net periodic pension and other postretirement benefit costs include the
following components:
Pension Benefits
--------------------------------------
2001 2000 1999
--------------------------------------
Service cost $ 13,494 $ 11,907 $ 8,481
Interest cost 27,742 26,469 12,823
Expected return on assets (28,806) (27,186) (11,712)
Amortization of:
Transition asset - - -
Prior service costs 1,195 1,201 841
Actuarial losses 200 159 976
----------- ----------- ------------
Net periodic benefit cost 13,825 12,550 11,409
Additional charges (credits):
Special termination charges 394 - 5,865
Curtailment credits - - (3,920)
----------- ----------- ------------
Total net benefit cost $ 14,219 $ 12,550 $ 13,354
=========== =========== ============
Other Postretirement Benefits
--------------------------------------
2001 2000 1999
--------------------------------------
Service cost $ 1,922 $ 1,775 $ 996
Interest cost 6,358 5,829 1,982
Expected return on assets (6,774) (5,327) (1,741)
Amortization of:
Prior service costs - - -
Transition obligation 969 968 1,344
Actuarial gains - (598) (596)
----------- ----------- ------------
Net periodic benefit cost 2,475 2,647 1,985
Additional charges (credits):
Special termination charges - - 1,312
Curtailment loss - - 1,283
----------- ----------- ------------
Total net benefit cost $ 2,475 $ 2,647 $ 4,580
=========== =========== ============
133
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 effects on 2001 service and interest
costs and the accumulated postretirement benefit obligation at year end:
One percentage point change Increase Decrease
--------------------------- -------- --------
Effect on service and interest
components of net periodic cost $ 708 $ (583)
Effect on accumulated postretirement
benefit obligation $ 6,961 $(5,839)
NOTE 15. STOCK COMPENSATION PLANS
At December 31, 2001, Sierra Pacific Resources had several stock-based
compensation plans which are described below. SPR applies Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to Employees, in accounting
for its stock option plans. Accordingly, no compensation cost has been
recognized for nonqualified stock options and the employee stock purchase plan.
The total compensation cost (benefit) that has been charged against income for
the performance shares, dividend equivalents, restricted stock grants, and the
non-employee director stock plans was $0.5 million for 2001, ($0.2 million) for
2000, and $0.2 million for 1999. SPR has adopted the disclosure-only provisions
of SFAS No. 123, Accounting for Stock Based Compensation. Had compensation cost
for SPR's nonqualified stock options and the employee stock purchase plan been
determined based on the fair value at the grant dates for awards under those
plans consistent with the provisions of SFAS No. 123, SPR's income applicable to
common stock would have been decreased to the pro forma amounts indicated below:
2001 2000 1999
--------------------------------
Net Income (Loss) As Reported $ 56,733 $ (39,780) $ 51,750
Pro Forma $ 55,524 $ (40,475) $ 50,908
Basic Earnings (Loss) Per Share As Reported $ 0.65 $ (0.51) $ 0.83
Pro Forma $ 0.63 $ (0.52) $ 0.81
Diluted Earnings (Loss) Per Share As Reported $ 0.65 $ (0.51) $ 0.83
Pro Forma $ 0.63 $ (0.52) $ 0.81
SPR's executive long-term incentive plan for key management employees,
which was approved by shareholders on May 16, 1994, provides for the issuance of
up to 750,000 of SPR's common shares to key employees through December 31, 2003.
On June 19, 2000, shareholders approved an increase of 1,000,000 shares for the
executive long-term incentive plan. 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 2001, SPR issued nonqualified stock options,
performance shares, and restricted stock under the long-term incentive plan.
Non-Qualified Stock Options
Nonqualified stock options granted during 2001 were issued at an option
price not less than market value at the date of the grants: January 1, May 15,
May 22, July 19, and November 15. The January 1 grant vests to the participants
33% per year over a 3 year period from the grant date, and the remaining grants
vest to the participants 25% per year over a four year period from the grant
date. All grants may be exercised for a
134
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.
A summary of the status of SPR's nonqualified stock option plan as of
December 31, 2001, 2000, and 1999, and changes during the year is presented
below:
-----------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
-------------------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Exercise Average Exercise Average
Nonqualified Stock Options Shares Price Shares Price Shares Exercise Price
-----------------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of year 799,428 $ 19.94 839,442 $ 24.33 289,126 $ 21.98
Granted/1/ 414,530 $ 15.08 400,000 $ 16.00 586,280 $ 25.35
Exercised - - 14,107 $ 14.28 1,286 $ 14.39
Forfeited - - 425,907 $ 25.07 34,678 $ 22.48
Outstanding at end of year 1,213,958 $ 18.28 799,428 $ 19.94 839,442 $ 24.33
Options exercisable at year-end 262,533 $ 23.03 202,394 $ 22.66 128,975 $ 20.53
Weighted-average grant date fair
value of options granted/2/:
November 15, 2001 $ 3.28
July 19, 2001 $ 4.62
May 22, 2001 $ 3.90
May 15, 2001 $ 4.05
January 1, 2001 $ 3.32
August 4, 2000 $ 4.10
August 1, 1999 $ 5.11
January 1, 1999 $ 4.05
-----------------------------------------------------------------------------------------------------------------------------
1. The number of nonqualified stock options granted during the year was 414,530
shares.
2. 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 2001, 2000 and 1999:
-------------------------------------------------------------------------------
Dividend Expected Risk-Free Rate of
Option Grant Date Yield Volatility Return Expected Life
-------------------------------------------------------------------------------
November 15, 2001 5.04% 32.37% 4.63% 10 years
July 19, 2001 4.47% 32.02% 5.66% 10 years
May 22, 2001 4.98% 32.48% 5.55% 10 years
May 15, 2001 4.98% 32.48% 5.55% 10 years
January 1, 2001 5.48% 32.22% 5.22% 10 years
August 4, 2000 4.81% 30.49% 6.14% 9.6 years
August 1, 1999 4.25% 17.41% 6.31% 10 years
January 1, 1999 4.40% 18.60% 5.08% 10 years
-------------------------------------------------------------------------------
135
The following table summarizes information about nonqualified stock
options outstanding at December 31, 2001:
-------------------------------------------------------------------------------------
Options Outstanding Options Exercisable
-------------------------------------------------------
Number Remaining Number
Exercise Outstanding Contractual Exercise Exercisable
Grant Date Price at 12/31/01 Life Price at 12/31/01
-------------------------------------------------------------------------------------
1/1/1994 $14.24 8,003 2 years $14.24 8,003
1/1/1995 $13.02 9,750 3 years $13.02 9,750
1/1/1996 $16.23 8,674 4 years $16.23 8,674
1/1/1997 $19.97 45,501 5 years $19.97 45,501
1/1/1998 $24.93 69,120 6 years $24.93 69,120
1/1/1999 $24.22 106,080 7 years $24.22 70,724
8/1/1999 $26.00 152,300 7.6 years $26.00 50,762
8/4/2000 $16.00 400,000 8 years $16.00 -
1/1/2001 $14.80 310,530 9 years $14.80 -
5/15/2001 $16.09 27,000 9.5 years $16.09 -
5/22/2001 $15.52 40,000 9.5 years $15.52 -
7/19/2001 $16.95 27,000 9.6 years $16.95 -
11/15/2001 $14.12 10,000 9.9 years $14.12 -
Weighted Average
Remaining 7.9 years
Contractual Life
------------------------------------------------------------------------------------
Each participant was granted dividend equivalents for all 1996 and
prior nonqualified option grants. Each dividend equivalent entitles the
participant to receive a contingent right to be paid an amount equal to
dividends declared on shares originally granted from the date of grant through
the exercise date. Dividend equivalents will be forfeited if options expire
unexercised.
Performance Shares
In 2001, 2000 and 1999, SPR granted performance shares in the following
numbers and initial values:
1/1/2001 8/4/2000 1/1/2000 1/1/1999
-----------------------------------------------
Shares Granted 135,906 4,798 31,707 28,944
Value per Share $ 14.80 $16.00 $ 26.00 $ 24.22
The actual number of shares earned by each participant is dependent
upon SPR achieving certain financial goals over three-year performance periods.
However, 66,100 shares included in the number granted on 1/1/2001 have a
one-year performance period, from January 1 through December 31, 2001. 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. The grant of 66,100 shares on
1/1/2001 will be paid in SPR stock only.
136
Simultaneous with the grant of the performance shares above, each
participant was granted dividend equivalents. Each dividend equivalent entitles
the participant to receive a contingent right to be paid an amount equal to
dividends declared on shares originally granted throughout the performance
period. Additionally, in order for dividend equivalents to be paid on the
performance shares, certain financial targets must be met. Dividend equivalents
will be forfeited if options expire unexercised.
Restricted Stock Shares
In 2001, SPR granted 13,200 restricted stock shares, detailed as
follows:
Grant Date
11/15/2001 7/19/2001 5/22/2001 5/15/2001
--------------------------------------------------
Shares Granted 2,400 2,500 4,000 4,300
Grant Price per Share $14.12 $16.95 $15.52 $16.09
Vesting Schedule for all: 4 years, 25% per year
In 2000, SPR granted 16,000 restricted stock shares at a grant price of
$16.00 per share. The grant vests over 4 years with 4,000 shares becoming
available in 2002, 4,000 shares in 2003, and 8,000 shares in 2004. No restricted
stock grants were issued in 1999. There are no performance criteria associated
with the restricted stock grants, and all grants were issued with an entitlement
to dividend equivalents.
Employee Stock Purchase Plan
Upon the inception of SPR's employee stock purchase plan, SPR was
authorized to issue up to 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 90% of the market value on the offering commencement date.
Employees can withdraw from the plan at any time prior to the exercise date.
Under the plan SPR sold 33,830, 46,773 and 21,888 shares to employees in 2001,
2000 and 1999, respectively. 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 2001, 2000 and
1999:
----------------------------------------------------------------
Average Average Average Weighted
Dividend Expected Risk-Free Average Fair
Year Yield Volatility Rate of Return Value
----------------------------------------------------------------
2001 5.01% 32.43% 2.82% $2.72
2000 4.72% 30.97% 5.86% $3.03
1999 4.31% 18.85% 5.08% $2.85
----------------------------------------------------------------
Non-Employee Director Stock Plan
SPR's non-employee director stock plan provides that a portion of the
outside directors' annual retainer be paid in SPR stock. Under the current plan,
the annual retainer for non-employee directors is $30,000, and the minimum
amount to be paid in SPR stock is $20,000 per director. During 2001, 2000 and
1999, SPR granted the following total shares and related compensation to
directors in SPR stock, respectively: 14,573, 16,915 and 4,741 shares, and
$210,000, $250,000 and $150,000. SPR did not pay out any phantom stock shares in
2001.
137
NOTE 16. POSTEMPLOYMENT BENEFITS
During 1999, SPR offered a severance program to non-bargaining-unit
employees, which provides for severance pay and medical benefits continuation
totaling $14.3 million and $0.8 million respectively. As approved by the PUCN in
1999, this cost is being deferred as a regulatory asset as of December 31, 2001.
The order approving the merger by the PUCN, directed the Utilities to defer
merger costs (including severance and related benefits) for a three-year period.
The deferral of these costs is intended to allow adequate time for the
anticipated savings from the merger to develop. At the end of the three-year
period, the order instructed the Utilities to propose an amortization period for
these costs, and allows SPPC and NPC to recover the costs to the extent that
they are offset by merger savings. The Utilities have filed a case with the PUCN
for recovery of these amounts and other merger costs. NPC and SPPC have proposed
recovery over a 10-year period, and expect a decision on their filings by April
1, 2002 and June 1, 2002, respectively. At December 31, 2001, the remaining
liability for unpaid severance was $0.4 million.
NOTE 17. DISCONTINUED OPERATIONS (SALE OF WATER BUSINESS)
On September 7, 2000, SPR and SPPC adopted a plan to sell SPPC's water
utility business, and on June 11, 2001, SPPC closed the sale of its water
business to the Truckee Meadows Water Authority (TMWA) for $341 million. SPPC
recorded a $25.8 million gain on the sale, net of the refund described below and
net of income taxes of $18.2 million. Included in the sale were facilities for
water storage, supply, transmission, treatment and distribution, as well as
accounts receivable and regulatory assets. Accounts receivable consisted of
amounts due from developers for distribution facilities. Regulatory assets
consisted primarily of costs incurred in connection with the Truckee River
negotiated water settlement. Transfer of hydroelectric facilities included in
the contract of sale for an additional $8 million will require action by the
California Public Utilities Commission (CPUC). The sale agreement contemplates a
second closing for the hydroelectric facilities to accommodate the CPUC's review
of the transaction.
Pursuant to a stipulation entered into in connection with the sale and
approved by the Public Utilities Commission of Nevada ("PUCN"), SPPC is required
to hold in trust for refund to customers $21.5 million of the proceeds from the
sale. The refund is being credited on the electric bills of SPPC's former water
customers over a period not to exceed fifteen months from June 11, 2001. Under a
service contract with TMWA, SPPC will provide, on an interim basis, customer
service, billing, and meter reading services to TMWA.
Revenues from operations of the water business for the years ended
December 31, 2001, 2000, and 1999 were $23 million, $57 million, and $54
million, respectively. The net income from operations of the water business, as
shown in the Consolidated Statements of Income of SPR, includes (in thousands)
preferred dividends of $200, $401, and $196 for the years ended December 31,
2001, 2000, and 1999, respectively. The income from operations of the water
business, as shown in the Consolidated Statements of Income of SPPC, includes
(in thousands) preferred dividends of $200, $401, and $528 for the years ended
December 31, 2001, 2000, and 1999, respectively. These amounts are not included
in the revenues and income (loss) from continuing operations shown in the
accompanying income statements.
NOTE 18. COMMITMENTS AND CONTINGENCIES
Construction
- ------------
The Utilities' combined estimated cash construction expenditures for
the year 2002 and the five-year period 2002-2006 are $470 million and $1.7
billion, respectively.
138
Purchased Power
- ---------------
NPC has three long-term contracts for the purchase of electric energy.
One of these contracts commences in 2004 and expires in 2012. NPC's other
contracts expire in 2016 and 2017. SPPC has one such contract that expires in
2009. Estimated future commitments under non-cancelable agreements with initial
terms of one year or more at December 31, 2001, were as follows (dollars in
thousands):
2002 $ 46,440
2003 152,852
2004 151,627
2005 136,680
2006 137,446
2007 to 2017 777,064
According to the regulations of the Public Utility Regulator Policies
Act, the Utilities are obligated, under certain conditions, to purchase the
generation produced by small power producers and cogeneration facilities at
costs determined by the appropriate state utility commission. Generation
facilities that meet the specifications of the regulations are known as
qualifying facilities (QFs). As of December 31, 2001, NPC had a total of 305 MWs
of contractual firm capacity under contract with four QFs. The contracts
terminate between 2022 and 2024. As of December 31, 2001, SPPC had a total of
109 MWs of maximum contractual firm capacity under 15 contracts with QFs. SPPC
also had contracts with three projects at variable short-term avoided cost
rates. One of SPPC's long-term QF contracts terminates in 2006, one terminates
in 2039, and the rest terminate between 2014 and 2022.
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 2006 to 2027. Estimated future commitments under non-cancelable agreements
with initial terms of one year or more at December 31, 2001 were as follows
(dollars in thousands):
Coal and Gas Transportation
2002 $ 42,870 $ 78,255
2003 39,528 86,499
2004 36,451 93,031
2005 17,534 79,137
2006 18,045 76,254
2007 to 2023 0 725,651
Leases
- ------
In 1984, NPC sold its administrative headquarters facility, less
furniture and fixtures, for $27 million and entered into a 30-year capital lease
of that facility with five-year renewal options beginning in year 31. The fixed
rental obligation for the first 30 years is $5.1 million per year. Future cash
rental payments as of December 31, 2001, were as follows (dollars in thousands):
139
2002 $ 6,156
2003 6,156
2004 6,946
2005 7,736
2006 7,736
2007 to 2014 58,016
The amount of imputed interest necessary to reduce the future cash
rental payments to present value is $44 million as of December 31, 2001. Total
interest expense on the lease obligation was $5.7 million and total amortization
of the leased facility was $(278,000) for the year ended December 31, 2001. The
total accumulated amortization of the leased facility on December 31, 2001, was
$8.6 million.
SPPC has an operating lease for its corporate headquarters building.
The primary term of the lease is 25 years, ending in 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 estimated future minimum cash payments, including SPPC's
headquarters building, under non-cancelable operating leases with initial terms
of one year or more at December 31, 2001, were as follows (dollars in
thousands):
2002 $ 12,127
2003 9,284
2004 8,194
2005 7,289
2006 6,863
2007 to 2045 63,463
Sale of Generation Assets
- -------------------------
As a condition to its approval of the merger between SPR and NPC, the
PUCN required the Utilities to file a Divestiture Plan for the sale of their
electric generation assets. The PUCN approved a revised Divestiture Plan
stipulation in February 2000. In May 2000 an agreement was announced for the
sale of NPC's 14% undivided interest in the Mohave Generating Station
("Mohave"). In the fourth quarter of 2000 the Utilities announced agreements to
sell six additional bundles of generation assets described in the approved
Divestiture Plan. The sales were subject to approval and review by various
regulatory agencies.
AB 369, which was signed into law on April 18, 2001, prohibits until
July 2003 the sale of generation assets and directs the PUCN to vacate any of
its orders that had previously approved generation divestiture transactions. In
January 2001, California enacted a law that prohibits until 2006 any further
divestiture of generation properties by California utilities, including SPPC,
and could also affect any sale of NPC's interest in Mohave after July 2003 since
the majority owner of that project is Southern California Edison. In addition,
SPPC's request for an exemption from the requirements of a separate California
law requiring approval of the CPUC to divest its plants was denied, subject to
future refiling.
The sales agreements for the six bundles provide that they terminate
eighteen months after their execution unless the parties agree to an earlier
termination. The parties may extend the termination another six months to obtain
additional regulatory approvals. As a result of the legislative and regulatory
developments which have rendered the contracts impossible to perform, the
Utilities are engaged in discussions with the buyers of the generation assets
regarding the formal termination of the sales agreements and the related energy
buyback contracts and interconnection agreements. As of December 31, 2001, NPC
and SPPC had incurred costs of approximately $12.3 million and $15.5 million,
respectively, in order to prepare for the sale of generation assets. The
Utilities have requested recovery of these costs in each Utility's respective
general rate case filing with the PUCN, discussed in Note 3, Regulatory Actions.
140
Environmental
- -------------
Nevada Power Company
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. The plant owners and plaintiffs have had numerous settlement
discussions and filed a proposed settlement with the court in October 1999. The
consent decree, approved by the court in November 1999, established emission
limits for sulfur dioxide and opacity and required installation of air pollution
controls for sulfur dioxide, nitrogen oxides and particulate matter. The new
emission limits must be met by January 1, 2006 and April 1, 2006 for the first
and second units respectively. However, if the owners sell their entire
ownership interest with a closing date prior to December 30, 2002, the new
emission limits become effective 36 months and 39 months from the date of last
closing for the two respective units. The estimated cost of new controls is $395
million. As a 14% owner in the Mohave Station, NPC's cost could be $55 million.
Also, the United States Congress authorized the EPA to study the
potential impact Mohave may have on visibility in the Grand Canyon area. A final
report of the study results was released in March 1999. The study acknowledges
that sulfur dioxide emissions from Mohave are transported to the Grand Canyon.
The EPA has solicited information to determine whether visibility impairment in
the Grand Canyon can be reasonably attributed to Mohave. The EPA determined that
significant visibility impairment to the Grand Canyon cannot be reasonably
attributable to the station provided controls are installed as agreed to in the
consent order. Therefore, the EPA will not require a Best Available Retrofit
Technology Review. Provisions that were agreed to in the settlement will be
reflected in the state Implementation Plan for Nevada.
In May 1997, NDEP ordered NPC to submit a plan to eliminate the
discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also
required a hydrological assessment of groundwater impacts in the area. In June
1999, NDEP determined that wastewater ponds had degraded groundwater quality. In
August 1999, 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 next 10 years. This order also required NPC to submit a Site
Characterization Plan to NDEP to ascertain impacts. This plan is under review by
NDEP. After approval, an estimate of remediation costs will be determined by
NPC. New pond construction and lining costs are estimated at $15 million.
Also, at the Reid Gardner Station, the NDEP has determined that there
is additional groundwater contamination that resulted from oil spills at the
facility. NDEP has required submitting a corrective action plan. The extent of
contamination has been determined and remediation is occurring at a modest rate.
An engineering evaluation of the current remediation technology will occur in
2002 to verify efficiency and to expedite remediation. Remediation modifications
are not expected to materially affect the financial position of SPR or NPC.
In May 1999, NDEP issued an order to eliminate the discharge of NPC's
Clark Station wastewater to groundwater. The order also required a hydrological
assessment of groundwater impacts in the area. This assessment, submitted to
NDEP in February 2001, warranted a Corrective Action Plan which was submitted to
NDEP in November and is pending review. Remediation costs are expected to be in
the $500,000 - $750,000 range. In addition to remediation, NPC will spend
$789,000 to line existing ponds. After review and approval of the Corrective
Action Plan by NDEP, NPC will implement remediation.
141
In July 2000, NPC received a request from the EPA for information to
determine the compliance of certain generation facilities at the Clark Station
with the applicable State Implementation Plan. In November 2000, NPC and the
Clark County Health District 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. If the EPA prevails, capital expenditures
and temporary outages of four of Clark Station's generation units could be
required. Additionally, depending on the time of year that the compliance
activity and corresponding generation outage would occur, the incremental cost
to purchase replacement energy could be substantial.
Sierra Pacific Power Company
In September 1994, Region VII of EPA notified SPPC that it was being
named as a potentially responsible party (PRP) regarding the past improper
handling of Polychlorinated Biphenyls (PCBs) by PCB Treatment, Inc., located in
Kansas City, Kansas, and Kansas City, Missouri (the Sites). The EPA is
requesting that SPPC voluntarily pay an undefined, pro rata share of the
ultimate clean-up costs at the Sites. A number of the largest PRP's formed a
steering committee, which is chaired by SPPC. The responsibility of the
Committee is to direct clean-up activities, determine appropriate cost
allocation, and pursue actions against recalcitrant parties, if necessary. The
EPA issued an administrative order on consent requiring signatories to perform
certain investigative work at the Sites. The steering committee retained a
consultant to prepare an analysis regarding the Sites. The Site evaluations have
been completed. EPA is developing an allocation formula to allocate the
remediation costs. SPPC has recorded a preliminary liability for the Sites of
$650,000 of which approximately $136,000 has been spent through December 31,
2001. Once evaluations are completed, SPPC will be in a better position to
estimate and record the ultimate liabilities for the Sites.
Other Subsidiaries of SPR
LOS, a wholly owned subsidiary of SPR, owns property in North Lake
Tahoe, California, which is leased to independent condominium owners. The
property has both soil and groundwater petroleum contaminate resulting from an
underground fuel tank that has been removed from the property. Additional
contaminate from a third party fuel tank on the property has also been
identified and is undergoing remediation. Estimated future remediation costs are
not expected to be significant.
NEICO, a wholly owned subsidiary of SPR, owns property in Wellington,
Utah, which was the site of a coal washing and load out facility. The site now
has a reclamation estimate supported by a bond of $4 million with the Utah
Division of Oil and Gas Mining. The property was under contract for sale and the
contract required the purchaser to provide $1.3 million in escrow towards
reclamation. However, the sales contract was terminated and NEICO took title to
the escrow funds. In September 2000, NEICO leased the property together with an
option to purchase. It is NEICO's intention to either lease or sell the
property.
Other Commitments and Contingencies
- -----------------------------------
SPR is a limited partner in an energy technology venture capital
partnership formed to gain access to new technologies that could affect SPR and
its subsidiaries. This partnership invests in energy companies offering
technologies of strategic advantage to its partners. The initial term of this
partnership expires in 2006, with two extensions of up to two years each. SPR's
investment in the partnership was $4.7 million as of December 31, 2001, of which
$325,000 was made in 2001. The remaining $300,000 balance of SPR's commitment is
expected to be drawn, as funds are needed by the partnership during 2002. Gains
and losses will be allocated 80% to the limited partners based on their
contributions, and 20% to the general partner. SPR, as a limited partner, is
entitled to 7.89%.
142
Certain of the Utilities' substations and portions of its generating
stations, transmission, distribution, and communication systems are located on
lands owned by units or agencies of federal, state and local governments under
licenses, permits, easements (collectively, "rights"). Except for those granted
in perpetuity, these rights may be canceled, with notice, at the will of the
grantor. Certain rights may impose restrictions and obligations on the
Utilities, including, but not limited to, care of property, limits on use, and
the right of inspection. Certain of the rights obligate the Utilities to make
periodic payments and may also allow the grantor to periodically reappraise the
lands on which the Utilities' property is located. Such reappraisals, which may
result in a change to the required periodic payments, may occur from annually to
every five years. In connection with these rights, the Utilities incurred
expenses of $1.41 million, $1.11 million and $1.38 million in 2001, 2000, and
1999, respectively.
Sierra Touch America LLC (STA), a partnership between SPC and Touch
America, a subsidiary of Montana Power Company, is constructing a fiber optic
line between Salt Lake City, Utah and Sacramento, CA. The conduits included in
the line are under contract to be sold to AT&T, PF Net corporations, and STA.
SPC is responsible for 50% of the partnership's operating expenses and shares in
the construction cost of the fiber network. Construction activity between
Sacramento and Reno commenced in July 2000, and the estimated completion date
has been moved to early 2003. Williams Communications, LLC ("Williams") has
filed a complaint in United States District Court alleging that STA has failed
to make timely payment on invoices in connection with a construction agreement
between Williams and STA. TI Energy Services ("TI") has filed a complaint in the
District Court of Harris County, Texas, alleging that STA has failed to make
timely payment on invoices in connection with a services agreement between TI
and STA, whereby TI is to provide services for certain segments of the fiber
optic line. Although SPC's ultimate liability, if any, cannot be estimated,
Management believes the final outcome of the litigation is not likely to have a
material adverse effect on SPR's financial position or results of operations.
SPPC owns a 345 kV transmission line that connects SPPC to the
facilities of the Bonneville Power Administration ("BPA") near Alturas,
California. The Transmission Agency of Northern California ("TANC") initiated
proceedings in the United States District Court for the Eastern District of
California and the United States Court of Appeals for the Ninth Circuit, in each
case alleging that BPA's construction of a small portion of the Alturas Intertie
violated the Northwest Power Preference Act and requesting an injunction
prohibiting operation of the Alturas Intertie. The case before the Eastern
District was dismissed for lack of jurisdiction. The case before the Ninth
Circuit was dismissed for TANC's failure to prosecute. In December 1999, TANC
filed suit in the Superior Court of the State of California, Sacramento County,
seeking an injunction against operation of the Alturas Intertie based on
numerous allegations under state law, including inverse condemnation, trespass,
private nuisance, and conversion. That case was removed to Federal Court and
dismissed by the trial court, and is now on appeal in the Ninth Circuit.
Although SPPC's ultimate liability, if any, cannot be estimated at this time,
Management believes the final outcome of the appeal and any subsequent
litigation is not likely to have a material adverse effect on SPR's financial
position or results of operation.
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 has had or, in the opinion of management, is expected to have, a
significant impact on its financial position or results of operations.
See Notes 3, 5, 6, 7, 8, 9, 12, 14, and, 16 of SPR's consolidated
financial statements for additional commitments and contingencies.
NOTE 19. SEGMENT INFORMATION
SPR operates three business segments (as defined by FASB statement No.
131, Disclosure about Segments of an Enterprise and Related Information)
providing regulated electric, natural gas and water service. Electric service is
provided to Las Vegas and surrounding Clark County, northern Nevada and the Lake
Tahoe
143
area of California. Natural gas and water services are provided in the
Reno-Sparks area of Nevada. Other segment information includes segments below
the quantitative threshold for separate disclosure.
On September 7, 2000, SPR and SPPC adopted a plan to sell SPPC's water
utility business. Accordingly, the water business is reported as a discontinued
operation and the consolidated financial statements have been reclassified to
report separately the net assets and operating results of the water business.
Therefore the water business is not reflected in the segment information below.
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. Intersegment revenues are not material.
In accordance with the requirements of purchase accounting and based on a
merger date of August 1, 1999, the segmented financial information for the
period ended December 31, 1999, includes five months of operating activity for
SPR's subsidiaries other than NPC.
Reconciling
December 31, 2001 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated
- ----------------- ------------------------------------------- --------- --------- ------------ ------------
Operating revenues $ 3,025,103 $ 1,399,134 $ 4,424,237 $ 145,652 $ 18,841 $ 4,588,730
Operating income 144,364 71,219 215,583 7,749 (463) - 222,869
Operating income taxes 17,775 5,534 23,309 2,973 (27,512) (1,230)
Depreciation 93,101 64,648 157,749 5,710 1,181 164,640
Interest expense on long term debt 81,599 50,071 131,670 5,128 51,572 188,370
Assets 5,225,369 2,336,479 7,561,848 264,108 270,038 85,320 8,181,314
Capital expenditures 200,852 117,563 318,415 16,041 - 334,456
Reconciling
December 31, 2000 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated
- ----------------- ------------------------------------------- --------- --------- ------------ ------------
Operating revenues $ 1,325,470 $ 893,782 $ 2,219,252 $ 100,803 $ 14,199 $ 2,334,254
Operating income 73,460 33,715 107,175 13,420 6,794 127,389
Operating income taxes (12,162) (3,944) (16,106) 3,272 (18,188) (31,022)
Depreciation 85,989 64,375 150,364 4,975 696 156,035
Interest expense on long term debt 64,513 32,547 97,060 4,318 33,218 134,596
Assets 3,407,751 1,722,725 5,130,476 151,905 61,768 333,759 5,677,908
Capital expenditures 204,505 117,429 321,934 14,490 23,350 359,774
Reconciling
December 31, 1999 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated
- ----------------- ------------------------------------------- --------- --------- ------------ ------------
Operating revenues $ 977,262 $ 259,440 $ 1,236,702 $ 38,958 $ 9,132 $ 1,284,792
Operating income 116,983 40,047 157,030 3,175 2,656 162,861
Operating income taxes 19,943 10,177 30,120 425 (5,247) 25,298
Depreciation 80,644 27,060 107,704 2,128 243 110,075
Interest expense on long term debt 64,454 11,415 75,869 1,326 299 77,494
Assets 2,748,329 1,607,312 4,355,641 153,347 426,881 300,048 5,235,917
Capital expenditures 223,963 51,798 275,761 7,051 16,252 299,064
144
The reconciliation of Capital expenditures for 2000 and 1999 represents
capital expenditures of the discontinued water business. The reconciliation of
segment assets at December 31, 2001, 2000, and 1999 to the consolidated total
includes the following unallocated amounts:
2001 2000 1999
-------- ---------- ----------
Other property $ - $ 1,998 $ 2,661
Cash 11,772 5,348 3,011
Current assets- other 50,862 29,852 3,103
Other regulatory assets 22,626 33,315 34,571
Net assets - discontinued operations - 261,479 256,365
Deferred charges- other 60 1,767 337
-------- ---------- ----------
$ 85,320 $ 333,759 $ 300,048
======== ========== ==========
Note 20. Subsequent Events
On February 6, 2002, a dividend of $975,000 ($0.4875 per share) was
declared on SPPC's preferred stock. The dividend is payable on March 1, 2002, to
holders of record as of February 8, 2002.
On February 6, 2002, SPR's Board of Directors declared a dividend on common
stock of 20 cents per share, payable March 15, 2002, to shareholders of record
at the close of business on February 22, 2002.
On February 6, 2002, NPC's Board of Directors declared a $10 million
dividend on NPC's common stock, all of which is held by SPR. On February 6,
2002, SPPC's Board of Directors declared a $10 million dividend on SPPC's common
stock, all of which is held by SPR. Both dividends were paid on March 15, 2002.
145
NOTE 21. 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.
Quarter Ended
March 31, 2001 June 30, 2001 September 30, 2001 December 31, 2001
Operating Revenues $ 737,926 $ 1,155,462 $ 1,971,900 $ 723,442
============== ============= ================== =================
Operating Income $ (30,487) $ 78,294 $ 122,190 $ 52,872
============== ============= ================== =================
Income (loss) from continuing operations $ (83,860) $ 27,549 $ 80,409 $ 5,768
Income from discontinued operations 381 641 - -
Gain on disposal of water business - 25,845 - -
-------------- ------------- ------------------ -----------------
Net income (loss) $ (83,479) $ 54,035 $ 80,409 $ 5,768
============== ============= ================== =================
Income (loss) per share-Basic:
Income (loss) from continuing perations $ (1.07) $ 0.35 $ 0.89 $ 0.06
Income from discontinued operations 0.01 0.01 - -
Gain on disposal of water business - 0.33 - -
-------------- ------------- ------------------ -----------------
Net income (loss) $ (1.06) $ 0.69 $ 0.89 $ 0.06
============== ============= ================== =================
Income (loss) per share-Diluted:
Income (loss) from continuing operations $ (1.07) $ 0.35 $ 0.89 $ 0.06
Income from discontinued operations 0.01 0.01 - -
Gain on disposal of water business - 0.33 - -
-------------- ------------- ------------------ -----------------
Net income (loss) $ (1.06) $ 0.69 $ 0.89 $ 0.06
============== ============= ================== =================
Quarter Ended
March 31, 2000 June 30, 2000 September 30, 2000 December 31, 2000
Operating Revenues $ 392,649 $ 474,312 $ 868,174 $ 599,119
============== ============= ================== =================
Operating Income $ 57,193 $ 15,144 $ 19,074 $ 35,978
============== ============= ================== =================
Income (loss) from continuing operations $ 17,251 $ (24,021) $ (23,742) $ (18,902)
Income from discontinued operations 927 3,830 4,194 683
-------------- ------------- ------------------ -----------------
Net income (loss) $ 18,178 $ (20,191) $ (19,548) $ (18,219)
============== ============= ================== =================
Income (loss) per share-Basic:
Income (loss) from continuing operations $ 0.22 $ (0.31) $ (0.30) $ (0.24)
Income from discontinued operations 0.01 0.05 0.05 0.01
-------------- ------------- ------------------ -----------------
Net income (loss) $ 0.23 $ (0.26) $ (0.25) $ (0.23)
============== ============= ================== =================
Income (loss) per share-Diluted:
Income (loss) from continuing operations $ 0.22 $ (0.31) $ (0.30) $ 0.24)
Income from discontinued operations 0.01 0.05 0.05 0.01
-------------- ------------- ------------------ -----------------
Net income (loss) $ 0.23 $ (0.26) $ (0.25) $ (0.23)
============== ============= ================== =================
146
NOTE 22. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)
Effective January 1, 2001, SPR, SPPC, and NPC adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138, both issued by
the Financial Accounting Standards Board. As amended, SFAS No. 133 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 qualifies as an effective hedge.
The adoption of this standard did not have a material impact on the
earnings of SPR or the Utilities. SPR and the Utilities did, however, recognize
all derivatives as assets or liabilities in the condensed consolidated balance
sheets upon adoption and measured those instruments at fair value. This resulted
in SPR, NPC, and SPPC recording $981 million, $678 million, and $303 million of
risk management assets, respectively, and $822 million, $722 million, and $97
million of risk management liabilities, respectively, at January 1, 2001.
On April 18, 2001, AB 369 was signed into law in Nevada. AB 369 reinstated
deferred energy accounting by the Utilities effective March 1, 2001. (See Note 3
- - Regulatory Actions, above.) As a result, fuel and purchased power expenses,
including gains and losses on derivative instruments, are recoverable or payable
through future rates. In accordance with SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," regulatory assets and liabilities are
established to the extent that such derivative gains and losses are recoverable
or payable through future rates. Because of this accounting treatment, the
Utilities will not apply hedge accounting to their electricity and natural gas
derivatives. However, SPR and the Utilities have adopted cash flow hedge
accounting for other derivative instruments not subject to regulatory treatment.
The transition adjustments resulting from adoption of SFAS No. 133 related to
the other derivative instruments not subject to regulatory treatment was
reported as the cumulative effect of a change in accounting principle in Other
Comprehensive Income of SPR and the Utilities.
SPR's and the Utilities' objective in using derivatives is to reduce
exposure to energy price risk and interest rate 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 include forwards, options, and swaps. These contracts
allow the Utilities to reduce the risks associated with volatile electricity and
natural gas markets.
Derivatives used to manage interest rate risk include interest rate swaps
designed to moderate exposure to interest-rate changes and lower the overall
cost of borrowing. At December 31, 2001, SPR had one interest rate swap related
to $200 million of SPR floating rate notes maturing April 20, 2003. This
interest rate swap is considered a completely effective cash flow hedge.
At December 31, 2001, the fair value of the derivatives resulted in the
recording of $347 million, $250 million and $97 million in risk management
assets and $1.019 billion, $601 million and $410 million in risk management
liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC,
respectively. The fair values of the forward contracts and swaps are determined
based on quotes obtained from independent brokers and exchanges. The fair values
of options are determined using a pricing model which 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.
Due to the regulatory environment in 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. Accordingly, at December 31, 2001, $664 million, $351 million and
$313 million in net
147
risk management regulatory assets were recorded in the Consolidated Balance
Sheets of SPR, NPC, and SPPC, respectively. In addition, for the twelve months
ended December 31, 2001, the unrealized gains and losses resulting from the
change in the fair value of derivatives designated and qualifying as cash flow
hedges for SPR, NPC, and SPPC were recorded in Other Comprehensive Income. Such
amounts will be reclassified into earnings when the related transactions are
settled or terminate. No amounts were reclassified into earnings during the
twelve months ended December 31, 2001.
Management has evaluated the impact of Derivatives Implementation Group
Issues C10 and C15 with respect to option contracts and optionality features. In
Management's opinion, the implementation of these interpretations will not
result in any changes to the initial application of SFAS No. 133 nor have a
significant impact on the financial position or results of operations of SPR or
the Utilities.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
148
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Directors
The following is a listing of all the current directors of SPR, NPC and
SPPC, and their ages as of December 31, 2001. There are no family relationships
among them. Directors serve 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 2002:
Krestine M. Corbin, 64
President and Chief Executive Officer of Sierra Machinery, Incorporated
since 1984 and a director of that company since 1980. She also serves on
the Federal Reserve Board of San Francisco Board of Directors. 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.
Fred D. Gibson, Jr., 73
Retired Chairman, President and Chief Executive Officer, but remains as a
director, of American Pacific Corporation, a manufacturer of chemicals
and pollution abatement equipment and a real estate developer. Mr. Gibson
has been affiliated with American Pacific Corporation and its
predecessor, Pacific Engineering & Production Co., since 1956. He is also
a director of Cashman Equipment Company. Mr. Gibson has served as a
Director of NPC since 1978, and was elected a Director of SPR and SPPC in
July 1999.
James L. Murphy, 71
Certified Public Accountant and retired partner of and consultant to
Grant Thornton L.L.P., an international accounting and management
consulting firm. Mr. Murphy is the owner, independent trustee, and
general partner of several real estate development projects and numerous
rental properties. He is also a retired colonel in the United States Air
Force Reserve. Mr. Murphy has served as a Director of SPPC since 1990, of
SPR since 1992, and was elected a Director of NPC in July 1999.
Clyde T. Turner, 64
Chairman and CEO of Turner Investments, Ltd., a general-purpose
investment company, and several special-purpose real estate development
companies known as Spectrum Companies in Las Vegas, Nevada. He is also a
director of St. Rose Dominican Hospital and CapCure, and a member of the
Environmental Advisory Committee to the Board of County Commissions,
Clark County, Nevada. Mr. Turner is the retired Chairman and Chief
Executive Officer of Mandalay Bay. He was elected a Director of SPR in
November 2001.
149
Dennis E. Wheeler, 59
Chairman, President and Chief Executive Officer of Coeur d'Alene Mines
Corporation since 1986. Mr. Wheeler has served as a Director of SPR since
1990, of SPPC since 1992, and was elected a Director of NPC in July 1999.
Directors whose terms expire in 2003:
Edward P. Bliss, 69
Consultant to Zurich Scudder Investments Co; retired partner, Loomis,
Sayles & Company, Inc., an investment counsel firm in Boston,
Massachusetts. He is also a Director of Seaboard Petroleum, Midland,
Texas. Mr. Bliss has served as a Director of SPR since 1991, of SPPC
since 1992, and was elected a Director of NPC in July 1999.
Mary Lee Coleman, 64
President of Coleman Enterprises, a developer of shopping centers and
industrial parks. She is also a director of First Dental Health. 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, 52
Senior Partner, Hale, Day, Gallagher Company, a real estate brokerage and
investment firm. 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. He is
also a Director of the W.M. Keck Foundation.
Jerry E. Herbst, 63
Chief Executive Officer of Terrible Herbst, Inc., a gas station, car
wash, convenience store chain; and Herbst Supply Co., Inc., a wholesale
fuel distributor; family-owned businesses for which he has worked since
1959. He is also a partner of the Coast Resorts (hotel and casino
industry). Mr. Herbst has served as a Director of NPC since 1990, and was
elected a Director of SPR and SPPC in July 1999.
Directors whose terms expire in 2004:
James R. Donnelley, 66
Partner, Stet & Query, Ltd., since June 2000. Retired, R.R. Donnelly &
Sons Company since June 2000, Vice Chairman of the Board, R.R. Donnelley
& Sons Company from July 1990 to June 2000, and a Director of that
company since 1976. Mr. Donnelley was R.R. Donnelley and Sons' Group
President, Corporate Development from June 1987 to July 1990, and Group
President, Financial Printing Services Group from January 1985 to January
1988. He is also a Director of Pacific Magazines & Printing Limited, and
Chairman of National Merit Scholarship Corporation. 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, 57
Chairman, President and Chief Executive Officer of SPR since August 8,
2000. Chairman, President and Chief Executive Officer of AGL Resources,
Inc., from February 1998 to August 2000. Chairman, President and Chief
Executive Officer of SPR from January 4, 1994 to January 14, 1998.
President and
150
Chief Operating Officer of Louisville Gas and Electric Company from 1991 to
November 1993. He is also a director of Aegis Insurance Services, Inc.
NEETF, American Gas Association, and Infrastrux.
John F. O'Reilly, 56
Chairman and Chief Executive Officer of the law firm of Mangels, Butler,
Marmaro & O'Reilly. He was formerly with the law firm of Keefer, O'Reilly,
and Ferrario. Mr. O'Reilly is also Chairman and Chief Executive Officer of
the O'Reilly Gaming Group and is on the Board of Trustees of Loyola
Marymount University. Mr. O'Reilly has served as a Director of NPC since
1995, and was elected a Director of SPR and SPPC in July 1999.
Messrs. Higgins and Murphy are Directors of Lands of Sierra, Inc.; Messrs.
Day and Higgins are Directors of Tuscarora Gas Pipeline Company; Mr. Higgins is
a Director of Sierra Pacific Communications, Sierra Water Development Company,
Sierra Gas Holdings Company, Pinon Pine Corporation, Pinon Pine Investment
Company, and GPSF-B. The Directors of e.three are Walter M. Higgins and Richard
J. Coyle. All of the above listed companies are subsidiaries of Sierra Pacific
Resources, with the exception of Pinon Pine Corporation, Pinon Pine Investment
Company, and GPSF-B, which are subsidiaries of Sierra Pacific Power Company.
(b) Executive Officers
The following are current executive officers of the companies indicated and
their ages as of December 31, 2001. 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, 57, Chairman, President and Chief Executive Officer, Sierra
Pacific Resources
See above description under Item 10(a), "Directors."
William E. Peterson, 54, Senior Vice President, General Counsel and Corporate
Secretary, Sierra Pacific Resources
Mr. Peterson was elected to his present position in January 1994, and holds
the same positions with SPPC and NPC. He was previously Senior Vice
President, Corporate Counsel for SPPC from July 1993 to January 1994. Prior
to joining SPR in 1993, he served as General Counsel and Resident Agent for
SPR since 1992, while a partner in the Woodburn and Wedge law firm. He was
a partner in the Woodburn and Wedge law firm since 1982.
Mark A. Ruelle, 40, President, Nevada Power Company
Mr. Ruelle was elected to his present position in May 2001. He was formerly
Senior Vice President and Chief Financial Officer for SPR since December
2000, and held the same positions with SPPC and NPC. Prior to joining SPR,
Mr. Ruelle was President of Westar Energy, a subsidiary of Western
Resources in 1996, and before that, served as Vice President, Corporate
Development for Western Resources in 1995. Mr. Ruelle was with Western
Resources since 1987 and served in numerous positions in regulatory
affairs, treasury, finance, corporate development, and strategy planning.
151
Jeffrey L. Ceccarelli, 46, President, Sierra Pacific Power Company
Mr. Ceccarelli was elected to his present position in June 2000. He
previously held the position of Vice President, Distribution Services, New
Business, in July 1999 for SPPC and NPC. He was elected Vice President,
Distribution Services for SPPC in February 1998. Prior to this, he served
as Executive Director, Distribution Services. From January 1996 through
January 1998, Mr. Ceccarelli was Director, Customer Operations. A civil
engineer, Mr. Ceccarelli has been with SPPC since 1972.
Dennis D. Schiffel, 58, Senior Vice President and Chief Financial Officer,
Sierra Pacific Resources
Mr. Schiffel was elected to his current position in July 2001. Previously,
he was vice President, Corporate Planning, for ARCO. He held various
positions there, including investor relations, finance, planning and
treasury at ARCO's parent company or operating units overseas.
Matt H. Davis, 45, Vice President, Transmission Services, Nevada Power Company
Mr. Davis was elected to his present position in November 2001. He was
formerly Vice President, Distribution Services for NPC. In the spring of
2000, he held a similar position forth both NPC and SPPC since July 1999.
Previously he was Director, System Planning, and Division Director, System
Planning and Operations for NPC. Mr. Davis has been with NPC since 1978.
Steven C. Oldham, 51, Senior Vice President, Energy Supply, Sierra Pacific Power
Company and Nevada Power Company
Mr. Oldham was elected to his current position in August 2001. Previously,
he was Senior Vice President, Corporate Development and Strategic Planning.
Previous to that, he was Vice President, Transmission Business Group and
Strategic Development; Vice President, Information Resources, Corporate
Redesign and Merger Transaction; Vice President, Regulation and Treasurer;
and Treasurer and Director of Finance. Mr. Oldham has been with SPPC since
1976.
Victor H. Pena, 53, Senior Vice President and Chief Administrative Officer,
Sierra Pacific Power Company and Nevada Power Company
Mr. Pena was elected to his current position in May 2001. From 1998 to his
appointment at SPPC and NPC, he held various executive positions at AGL
Resources, Inc., in Atlanta, Georgia, including Vice President, Business
Development, and Vice President, Financial Systems and Controller.
Mary O. Simmons, 46, Vice President, Rates and Regulatory Affairs, Sierra
Pacific Power Company and Nevada Power Company
Ms. Simmons was elected to her current position in May 2001. Previously she
held the position of Controller for SPR since July 1999, and held the same
position with SPPC and NPC. Her previous positions include: Director, Water
Policy and Planning; Director, Budgets and Financial Services; and
Assistant Treasurer, Shareholder Relations for SPR. Ms. Simmons is a
certified public accountant and has been with SPR since 1985.
Douglas R. Ponn, 54, Vice President, Public Policy, Sierra Pacific Power Company
and Nevada Power Company
Mr. Ponn was elected to his present position in May 2001. Formerly he held
the position of Vice President, Governmental and Regulatory Affairs, since
July 1999 for both SPPC and NPC. Previously
152
he was Executive Director, Governmental and Regulatory Affairs. Mr. Ponn
has been with SPR since 1986.
Mary Jane Reed, 55, Vice President, Human Resources, Sierra Pacific Power
Company and Nevada Power Company
Ms. Reed was elected Vice President, Human Resources of SPPC in January
1997, and was named to the same position with NPC in July 1999. She was
previously Vice President, Human Resources, Network Group for Bell Atlantic
Corporation. Ms. Reed was with Bell Atlantic from 1968 - 1996 and, in
addition to the Vice President's position, served as Director of Human
Resources, Assistant to the President for Consumer Affairs, and several
other managerial positions.
Richard K. Atkinson, 50, Treasurer and Investor Relations Officer, Sierra
Pacific Resources
Mr. Atkinson was elected to his current position in May 2001 and holds the
same position with SPPC and NPC. He was formerly Treasurer of SPR, SPPC,
and NPC in December 2000. Previously he held the positions of Assistant
Treasurer, Executive Director, Finance, and other positions in the Finance
Department. Mr. Atkinson has been with SPPC since 1980.
Michael R. Smart, 45, Vice President, Resource Management, Sierra Pacific Power
Company and Nevada Power Company
Mr. Smart was appointed to his present position in May 2001. He was
formerly Acting Vice President, Resource Management, since October 2000.
Previously he was Executive Director, Resource Management for SPPC and NPC
effective August 1999. Prior to this, from February 1998, he served as
Director, Electric Operations for SPPC. From August 1996 to February 1998,
he was Director of Energy Sales. A registered electrical engineer in Nevada
and California, Mr. Smart has been with SPPC since 1979 and has held
numerous management positions in operations, engineering, and planning.
Paul Heagen, 49, Vice President, Marketing and Corporate Communications, Sierra
Pacific Power Company and Nevada Power Company
Mr. Heagen was appointed to his present position in 2001. He has held
various positions at GTE Corporation in all areas of utility
communications, marketing, public policy, crisis management, corporate
branding, and communications strategy.
Carol Marin, 50, Vice President, Customer Service, Sierra Pacific Power Company
and Nevada Power Company
Ms. Marin was elected to her present position in May 2001. Previously she
held the position of Director, Customer Information Systems Project for
both companies from August 1999-May 2001. From 1977 until 1999, Ms. Marin
served in a variety of management positions for SPPC in customer service,
major accounts, and operations analysis. Ms. Marin has been with SPPC for
25 years.
Susan Brennan, 42, Vice President, Information Services, Sierra Pacific Power
Company and Nevada Power Company.
Ms. Brennan was elected to her present position in May 2001. Previously she
held the position of Executive Director, Customer Service, from august 1999
to May 2001. From 1992 to 1999, Ms. Brennan served in various financial and
industry restructuring positions. Ms. Brennan has been with NPC 10 years.
153
John Brown, 51, Controller, Sierra Pacific Resources
Mr. Brown was elected to his present position in May 2001 and holds the
same position at SPPC and NPC. Previously he held the position of Director,
Corporate and Tax Accounting. Mr. Brown has held a variety of positions in
SPR, including Compliance Officer, Director, Shareholder Relations, and
Director, Internal Audit. Mr. Brown has been with SPR 21 years.
Although all outstanding shares of SPPC's common stock are held by SPR and
it is SPR's common stock which is traded on the New York Stock Exchange, SPPC
has one series of non-voting preferred stock outstanding and registered under
the Securities Exchange Act of 1934 ("the Act"). As a technical matter, SPPC is
thus deemed an "issuer" for purposes of the Act whose officers are required to
make filings with respect to beneficial ownership, if any, of those non-voting
preferred securities. SPPC's officers, all of whom are currently reporting
pursuant to Section 16(a) of the Act with respect to SPR's common stock, have
filed reports with respect to SPPC's preferred stock, which reports show no past
or current beneficial ownership of such preferred stock.
154
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth information about the compensation of the
Chief Executive Officer that served in that position during 2001, and each of
the four most highly compensated officers for services in all capacities to SPR
and its subsidiaries. Also included is an individual who, although not an
officer at the end of 2001, warranted inclusion due to compensation levels.
- ------------------------------------------------------------------------------------------------------------------------------------
Annual Compensation Long-Term Compensations
---------------------------------------------------------------------------------------------------
Awards Payout
----------------------------------------------------------
Securities
Underlying All Other
Name and Principal Other Annual Restricted Stock Options/SARs LTIP Payouts Compensations
Position Year Salary ($) Bonus ($) Compensation ($) Awards ($) (#) ($) ($)
(a) (b) (c) (d)(2) (e)(3) (f)(4) (g)(5) (h)(6) (i)(7)
- ------------------------------------------------------------------------------------------------------- ----------------------------
Walter M Higgings 2001 $ 590,000 $ - $ 70,970 $ - 110,130 $ - $ 614,129
Chairman of the Board, 2000 $ 215,151 $ - $ 33,690 $ 256,000 400,000 $ - $ 411,758
President, and Chief
Executive Officer
Mark A. Ruelle 2001 $ 280,962 $ - $ 28,108 $ 62,080 66,520 $ - $ 109,437
President Nevada Power 2000 $ 250,255 $ - $ 15,967 $ - - $ 59,357 $ 19,160
Company 1999 $ 196,654 $ 86,658 $ 7,389 $ - 61,292 $ - $ 8,565
Steven W. Rigazio/1/ 2001 $ 255,000 $ - $ 843 $ - 26,520 $ - $ 573,177
President, Nevada Power 2000 $ 255,003 $ - $ 15,477 $ - - $ 26,713 $ 201,227
Company 1999 $ 262,075 $ 81,700 $ 60,654 $ - 36,260 $ 27,712 $ 6,811
William E. Peterson 2001 $ 231,538 $ - $ 31,606 $ - 22,880 $ - $ 20,456
Senior Vice President 2000 $ 216,203 $ - $ 25,943 $ - - $ 59,357 $ 20,926
General Counsel and 1999 $ 200,000 $ 83,053 $ 20,727 $ - 80,168 $ - $ 11,974
Corporate Secretary
Jeffrey L. Cecarelli 2001 $ 221,539 $ - $ 13,712 $ - 22,510 $ - $ 19,429
President, Sierra Pacific 2000 $ 191,539 $ - $ 19,320 $ - - $ 36,527 $ 16,781
Power Company 1999 $ 148,077 $ 26,840 $ 8,321 $ - 26,140 $ - $ 1,484
Steven C. Oldham 2001 $ 219,039 $ - $ - $ - 20,800 $ - $ 19,775
Senior Vice President, 2000 $ 186,584 $ - $ 13,750 $ - - $ 36,527 $ 19,678
Energy Supply 1999 $ 151,058 $ 26,840 $ 8,859 $ - 41,286 $ - $ 7,970
- ------------------------------------------------------------------------------------------------------------------------------------
1. Mr. Rigazio was President of Nevada Power Company until the appointment of
Mr. Ruelle to that position in May 2001.
2. The amounts presented for 1999 represent incentive pay received pursuant to
SPR's "pay for performance" team incentive plan approved by stockholders in
May, 1994. All of the amounts are reported in the year they were earned,
although payment may have occurred in a subsequent reporting period. The
Board of Directors elected not to grant payment of the 2000 and 2001
incentive pay to the executives.
3. For all of the executives listed these amounts represent Personal Time Off
payouts.
4. As the result of a promotion, Mr. Ruelle was awarded a restricted stock
grant of 4,000 shares with dividend equivalents. At December 31, 2001, the
value of the grant was $60,200 at $15.05 per share. The grant will vest
over a four year period at 25% per year.
In 2000, Mr. Higgins was awarded a restricted stock grant of 16,000 shares
with dividend equivalents. At December 31, 2001, the value of the grant was
$240,800 at $15.05 per share. The grant will vest over a four year period
in the following manner:
155
September 2002 4,000 shares
September 2003 4,000 shares
September 2004 8,000 shares
5. As a result of the August 1, 1999 merger with Nevada Power Company, all SPR
nonqualifying stock options outstanding as of that date were converted at a
ratio of 1.44:1. For the pre-merger SPR executives, the 1999 option amounts
include the number of new shares issued during the year, as well as the
total number of shares that were converted for that employee. The 2000
Non-Qualified Stock Options were granted in August of 1999 and are
therefore included in the 1999 amounts.
6. The Long-term incentive payouts for the SPR executives, for the three-year
periods ended December 31, 1999 and December 31, 2001, were not approved
for payment by the SPR Board of Directors; therefore, for these payouts,
zero amounts are shown in 1999 for the pre-merger SPR executives, and in
2001 for all executives. In 1999, Nevada Power executives received a lump
sum payout of all their performance shares as a result of the August 1,
1999 merger.
7. Amounts for All Other Compensation include the following for 2001:
-------------------------------------------------------------------------------------------------------------------
Walter M. Mark A. Steven W. William E. Jeffrey L. Steven C.
Description Higgins Ruelle Rigazio Peterson Ceccarelli Oldham
-------------------------------------------------------------------------------------------------------------------
Company contributions to the 401k $ 10,200 $ 9,600 $ 10,200 $ 8,400 $ 10,200 $ 10,200
deferred compensation plan
Company paid portion of $ 7,752 $ 7,180 $ 7,752 $ 7,752 $ 7,752 $ 7,752
Medical/Dental/Vision Benefits
Company contributions to the $ 646 $ 1,935
nonqualified deferred compensation plan
Imputed income on group term life $ 3,612 $ 400 $ 600 $ 773 $ 477 $ 690
insurance premiums paid by SPR
Insurance premiums paid for executive $ 7,746 $ 563 $ 1,596 $ 1,000 $ 1,133
term life policies
Moving Expense Reimbursement (includes $ 418,211 $ 91,048
closing costs on sale of home)
Additional Compensation upon Rehire $ 72,865
Taxable Interest on Refund of $ 24,935
Non-Qualified Pension Contribution
Housing Allowance $ 64,122
Spouse Travel Expense Reimbursement $ 4,686
Severance/Stay Agreement payments $ 554,625
Total $ 614,129 $ 109,437 $ 573,177 $ 20,456 $ 19,429 $ 19,775
-------------------------------------------------------------------------------------------------------------------
Options/SAR Grants in Last Fiscal Year
The following table shows all grants of options to the named executive
officers of SPR in 2001. Pursuant to Securities and Exchange Commission (SEC)
rules, the table also shows the present value of the grant at the date of grant.
156
--------------------------------------------------------------------------------------------------------------
Number of Percent of Total
Securities Options/SAR's
Underlying Granted to Exercise of
Options/SAR's Employees in Base Price Grant Date
Name Granted Fiscal Year ($/share) Expiration Date Present Value
(a) (b) (1) (c) (2) (d) (e) (f)(3)
--------------------------------------------------------------------------------------------------------------
Walter M. Higgins
01/01/2001 Grant date 110,130 26.57% $14.80 01/01/2011 $365,632
Mark A. Ruelle
01/01/2001 Grant date 26,520 6.40% $14.80 01/01/2011 $ 88,046
05/22/2001 Grant date 40,000 9.65% $15.52 05/22/2011 $156,000
Steven W. Rigazio
01/01/2001 Grant date 26,520 6.40% $14.80 01/01/2011 $ 88,046
William E. Peterson
01/01/2001 Grant date 22,880 5.52% $14.80 01/01/2011 $ 75,962
Jeffrey L. Ceccarelli
01/01/2001 Grant date 22,510 5.43% $14.80 01/01/2011 $ 74,733
Steven C. Oldham
01/01/2001 Grant date 20,800 5.02% $14.80 01/01/2011 $ 69,056
--------------------------------------------------------------------------------------------------------------
1. Under the SPR executive long-term incentive plan, the 2001 grants of
nonqualifying stock options were made on January 1, 2001. One-third of
these grants vest annually commencing one year after the date of the grant.
An additional grant of 40,000 shares of nonqualifying stock options was
made to Mr. Ruelle as the result of a promotion. This grant vests at a rate
of one-quarter per year for four years beginning one year after the grant
date of May 22, 2001.
2. The total number of nonqualifying stock options granted to all employees in
2001 was 414,530.
3. The hypothetical grant-date present values are calculated under the
Black-Scholes Model. The Black-Scholes Model is a mathematical formula used
to value options traded on stock exchanges. The assumptions used in
determining the option grant date present values listed above include the
stock's average expected volatility (32.31%), average risk free rate of
return (5.32%), average projected dividend yield (4.99%), the stock option
term (10 years), and an adjustment for risk of forfeiture during the
vesting period (4 years at 3%). No adjustment was made for
non-transferability.
Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year-End
Option/SAR Values
The following table provides information as to the value of the options
held by the named executive officers at year end measured in terms of the
closing price of Sierra Pacific Resources common stock on December 31, 2001.
-------------------------------------------------------------------------------------------------------------------
Shares Number of Securities Underlying Value of Unexercised in-the-
Acquired on Value Unexercised Options/SARs at money Options/SARs at
Name Exercise Realized Fiscal Year-End Fiscal Year-End
(a) (b) (c) (d) (e)
---------------------------------------------------------------
Exercisable Unexercisable Exercisable Unexercisable
-------------------------------------------------------------------------------------------------------------------
Walter M. Higgins - - - 510,130 $ - $ 27,533
Mark A. Ruelle - - 41,439 86,374 $ - $ 6,630
Steven W. Rigazio - - 16,406 46,374 $ - $ 6,630
William E. Peterson - - 60,317 42,734 $ 16,768 $ 5,720
Jeffrey L. Ceccarelli - - 16,633 32,017 $ - $ 5,628
Steven C. Oldham - - 31,780 30,307 $ 8,028 $ 5,200
-------------------------------------------------------------------------------------------------------------------
(e) Pre-tax gain. Value of in-the-money options based on December 31, 2001
closing trading price of $15.05 less the option exercise price.
157
Long-Term Incentive Plans-Awards in Last Five Years
The executive long-term incentive plan (LTIP) provides for the granting
of stock options (both nonqualified and qualified), stock appreciation rights
(SARs), restricted stock performance units, performance shares and bonus stock
to participating employees as an incentive for outstanding performance.
Incentive compensation is based on the achievement of pre-established financial
goals for SPR. Goals are established for total shareholder return (TSR) compared
against the Dow Jones Utility Index and annual growth in earnings per share
(EPS).
The following table provides information as to the performance shares
granted to the named executive officers of Sierra Pacific Resources in 2001.
Nonqualifying stock options granted to the named executives as part of the LTIP
are shown in the table "Option/SAR Grants in Last Fiscal Year."
---------------------------------------------------------------------------------------------------------
Performance or Estimated Future Payouts Under Non-Stock
Number of Other Period Price-Based Plans
------------------------------------------------
Shares, Units Until
or Other Maturation or
Name Rights Payout Threshold ($) Target ($) Maximum ($)
(a) (b) (c) (d)(1) (e)(2) (f)(3)
---------------------------------------------------------------------------------------------------------
Walter M. Higgins 20,650 3 years $ 152,810 $ 305,620 $ 534,835
Mark A. Ruelle 4,970 3 years $ 36,778 $ 73,556 $ 128,723
Steven W. Rigazio 4,970 3 years $ 36,778 $ 73,556 $ 128,723
William E. Peterson 4,290 3 years $ 31,746 $ 63,492 $ 111,111
Jeffrey L. Ceccarelli 4,220 3 years $ 31,228 $ 62,456 $ 109,298
Steven C. Oldham 3,900 3 years $ 28,860 $ 57,720 $ 101,010
---------------------------------------------------------------------------------------------------------
1. The threshold represents the level of TSR and EPS achieved during the cycle
which represents minimum acceptable performance and which, if attained, results
in payment of 50% of the target award. Performance below the minimum acceptable
level results in no award earned.
2. The target represents the level of TSR and EPS achieved during the cycle
which indicates outstanding performance and which, if attained, results in
payment of 100% of the target award.
3. The maximum represents the maximum payout possible under the plan and a level
of TSR and EPS indicative of exceptional performance which, if attained, results
in a payment of 175% of the target award.
All levels of awards are made with reference to the price of each
performance share at the time of the grant.
Pension Plans
The following table shows annual benefits payable on retirement at
normal retirement age 65 to elected officers under SPR's qualified and
non-qualified defined benefit plans based on various levels of remuneration and
years of service which may exist at the time of retirement. The amounts below
are based upon a maximum benefit of 60% of final average earnings used under the
Supplemental Executive Retirement Plan. This maximum is reduced to 50% for any
Officer who became a participant after November 1, 1999.
158
---------------------------------------------------------------------------------------
Annual Benefits for Years of Service Indicated
---------------------------------------------------------------------
Highest Average
Five-Years 15 Years 20 Years 25 Years 30 Years 35 Years
Remuneration
---------------------------------------------------------------------------------------
$ 60,000 $ 27,000 $ 31,500 $ 36,000 $ 36,000 $ 36,000
$120,000 $ 54,000 $ 63,000 $ 72,000 $ 72,000 $ 72,000
$180,000 $ 81,000 $ 94,500 $108,000 $108,000 $108,000
$240,000 $108,000 $126,000 $144,000 $144,000 $144,000
$300,000 $135,000 $157,500 $180,000 $180,000 $180,000
$360,000 $162,000 $189,000 $216,000 $216,000 $216,000
$420,000 $189,000 $220,500 $252,000 $252,000 $252,000
$480,000 $216,000 $252,000 $288,000 $288,000 $288,000
$540,000 $243,000 $283,500 $324,000 $324,000 $324,000
$600,000 $270,000 $315,000 $360,000 $360,000 $360,000
$660,000 $297,000 $346,500 $396,000 $396,000 $396,000
$720,000 $324,000 $378,000 $432,000 $432,000 $432,000
---------------------------------------------------------------------------------------
SPR's noncontributory qualified retirement plan provides retirement
benefits to eligible employees upon retirement at a specified age. Annual
benefits payable are determined by a formula based on years of service and final
average earnings consisting of base salary and incentive compensation.
Remuneration for the named executives is the amount shown in columns (c) and (d)
of the Summary Compensation Table. Pension costs of the retirement plan, to
which SPR contributes 100% of the funding, are not and cannot be readily
allocated to individual employees and are not subject to Social Security or
other offsets.
The years of credited service under the qualified retirement plan for
the named executives are as follows: Mr. Higgins 5.5, Mr. Ruelle 4.7, Mr.
Rigazio 17.4, Mr. Peterson 8.4, Mr. Ceccarelli 27.3, and Mr. Oldham 25.2.
A supplemental executive retirement plan (SERP) and a restoration plan
are also offered to the named executive officers. The SERP is intended to ensure
the payment of a competitive level of retirement income to attract, retain and
motivate selected executives. The Restoration Plan is intended to provide
benefits to executive officers whose benefits cannot be paid under the qualified
plan because of salary deferrals to the Non-Qualified Deferred Compensation
Plan, IRS limitations on compensation that can be recognized by a qualified
plan, and IRS limitations on benefits payable from a qualified plan.
The years of credited service under the non-qualified SERP are as
follows: Mr. Higgins 8.1, Mr. Ruelle 4.7, Mr. Rigazio 17.4, Mr. Peterson 16.4,
Mr. Ceccarelli 27.3, and Mr. Oldham 25.2.
Severance Arrangements
Individual severance allowance plans exist for the named executive
officers which provide for severance pay, payable in a lump sum or by purchase
of an annuity, if within three years after a change in control of SPR, there is
a termination of employment by SPR related to such change in control, or a
termination of employment by the employee for good reason, in each case as
described in the plans. In these circumstances, officers are entitled to a
severance allowance not to exceed an amount equal to 36 months of the officer's
base salary and any bonus and the continuation for up to 36 months of
participation in SPR's group medical and life insurance plans. Change in control
is defined in the plans as, among other things, a dissolution or liquidation, a
reorganization, merger or consolidation in which SPR is not the surviving
corporation, the sale of all or substantially all the assets of SPR (not the
sale of a work unit) or the acquisition by any person or entity of 30% or more
of the voting power of SPR.
159
In addition, several merger-related and merger-conditioned severance
arrangements have been entered into between SPR and several executives, which
are described in Item 13 - Certain Relationships and Related Transactions.
160
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Voting Stock of SPR
The following table indicates the shares owned by Franklin Advisors,
and Putnam Investments, the only investors known to Sierra Pacific Resources to
be owners of more than 5 percent of any class of its voting stock as of March
11, 2002.
Name and Address of Shares Beneficially
Title of Class Beneficial Owner Owned Percent of Class
-------------- ---------------- ----- ----------------
Common Stock Franklin Advisors 9,978,000 10.8%
777 Mariners Island Blvd.
San Mateo, Ca. 94404
Common Stock Putnam Investors 5,400,000 5.3%
One Post Office Square
Boston, Ma. 02109
The table below sets forth the shares of SPR Common Stock beneficially
owned by each director, nominee for director, the Chief Executive Officer, and
the four other most highly compensated executive officers. No director, nominee
for director or executive officer owns, nor do the directors and executive
officers as a group own, in excess of one percent of the outstanding Common
Stock of SPR. Unless otherwise indicated, all persons named in the table have
sole voting and investment power with respect to the shares shown.
Common
Shares
Beneficially Percent of Total Common
Name of Director Owned as of Shares Outstanding as of
or Nominee March 11, 2002 March 11, 2002
- ------------------------ ---------------- ------------------------------
Edward P. Bliss 29,450
Mary L. Coleman 150,634
Krestine M. Corbin 22,271
Theodore J. Day 36,130 No director or nominee
James R. Donnelley 37,429 for director owns in excess
Fred D. Gibson Jr. 24,095 of one percent.
Jerry E. Herbst 15,479
Walter M. Higgins 49,868
James L. Murphy 34,268
John F. O'Reilly 14,985
Clyde T. Turner 0
Dennis E. Wheeler 19,994
--------------
434,603
==============
161
Common Shares
Beneficially Percent of Total Common
Owned as of Shares Outstanding as of
Executive Officers March 11, 2002 March 11, 2002
- -------------------------------- ------------------ ----------------------------
Walter M. Higgins 49,868
Steven W. Rigazio (1) 16,406 No executive officer owns
Mark A. Ruelle 47,244 In excess of one percent
William E. Peterson 88,294
Jeffrey L. Ceccarelli 44,422
Steven C. Oldham 55,891
------
302,125
=======
All directors and executive
officers as a group (a)(b)(c) 862,753
=======
(1) Mr. Rigazio was President of Nevada Power Company until the appointment of
Mr. Ruelle to that position in May 2001.
(a) Includes shares/units acquired through participation in the Employee Stock
Purchase Plan and/or the 401(k) plan.
(b) The number of shares beneficially owned includes: shares the Executive
Officers currently have the right to acquire pursuant to stock options
granted, and performance shares earned under the Executive Long-Term
Incentive Plan. Shares beneficially owned pursuant to stock options granted
to Messrs. Higgins, Rigazio, Peterson, Ruelle, Ceccarelli, Oldham, and
directors and executive officers as a group are 0, 16,406, 80,029, 62,366,
30,210, 44,787, and 338,409 shares, respectively.
(c) Included in the shares beneficially owned by the Directors are 100,172
shares of "phantom stock" representing the actuarial value of the
Director's vested benefits in the terminated Retirement Plan for Outside
Directors. The "phantom stock" is held in an account to be paid at the time
of the Director's departure from the Board.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Transactions with Management
- ----------------------------
Mr. Peterson, formerly a partner with the law firm of Woodburn and
Wedge, became Senior Vice President and General Counsel for Sierra Pacific
Resources in 1993. Woodburn and Wedge, which has performed legal services for
SPPC since 1920 and for Sierra Pacific Resources and all of its subsidiaries
from their inception, continues to perform legal work for SPR. Mr. Peterson's
spouse, an equity partner in the firm since 1982, has performed work for SPR
since 1976 and continues to do so from time to time.
Susan Oldham, a former employee of SPPC specializing in water resources
law, planning and policy, accepted SPPC's voluntary severance offering in
December 1995. Ms. Oldham is the spouse of Steven C. Oldham, Senior Vice
President, Energy Supply, for NPC and SPPC. Ms. Oldham, a licensed attorney in
Nevada and California, performed specialized legal services in the water
resources area for SPR on a contract basis through June 2001.
Change in Control Agreements
- ----------------------------
SPR has entered into change in control severance agreements with
Walter M. Higgins, Jeffrey L. Ceccarelli, Steven C. Oldham, William E. Peterson,
Mark A. Ruelle, Victor H. Pena, Dennis D. Schiffel, Mary
162
O. Simmons, Susan Brennan, Carol Marin, Paul Heagen, Richard K. Atkinson, John
Brown, Douglas R. Ponn, Michael R. Smart, Matt H. Davis, and Mary Jane Reed.
These agreements provide that, upon termination of the executive's employment
within 24 or 36 months following a change in control of SPR (as defined in the
agreement either (a) by SPR for reasons other than cause (as defined in the
agreements), (b) death or disability, or (c) by the executive for good reason as
defined in the agreement, including a diminution of responsibilities,
compensation, or benefits (unless, with respect to reduction in salary or
benefits, such reduction is applicable to all senior executives of SPR and the
acquirer)), the executive will receive certain payments and benefits. These
severance payments and benefits include (i) a lump sum payment equal to two or
three times the sum of the executive's base salary and target bonus, (ii) a lump
sum payment equal to the present value of the benefits the executive would have
received had he continued to participate in SPR's retirement plans for an
additional two or three years (or, in the case of SPR's Supplemental Executive
Retirement Plan only, the greater of three years or the period from the date of
termination until the executive's early retirement date, as defined in such
plan), and (iii) continuation of life, disability, accident and health insurance
benefits for a period of 24 or 36 months immediately following termination of
employment. The agreements also provide that if any compensation paid, or
benefit provided, to the executive, whether or pursuant to the change in control
agreements, would be subject to the federal excise tax on "excess parachute
payments," payments and benefits provided pursuant to the agreement will be cut
back to the largest amount that would not be subject to such excise tax, if such
cutback results in a higher after-tax payment to the executive. The Board of
Directors entered into these agreements in order to attract and retain excellent
management and to encourage and reinforce continued attention to the executives'
assigned duties without distraction under circumstances arising from the
possibility of a change in control of SPR. In entering into these agreements,
the Board was advised by Towers Perrin, the national compensation and benefits
consulting firm described above, and Skadden, Arps, Slate, Meagher & Flom, an
independent outside law firm, to insure that the agreements entered into were in
line with existing industry standards, and provided benefits to management
consistent with those standards. The new contracts expire on December 31, 2003,
unless renewed or replaced before that time.
Employment Agreements
- ---------------------
Walter M. Higgins
On August 4, 2000, SPR elected Walter M. Higgins as President, Chief
Executive Officer and Chairman of the Board under terms and conditions of an
employment offer. The terms and conditions of that agreement essentially
replicate Mr. Higgins' compensation and benefits package provided by his
previous employer, AGL Resources, and make him whole for benefits and
compensation lost, forgone, or otherwise forfeited as a result of his accepting
employment with SPR.
SPR engaged Towers Perrin to evaluate Mr. Higgins' offer prior to
consummating it in order to assure that it was consistent with SPR policy to
compensate its senior executives, including the Chief Executive Officer, at or
near the midpoint of the competitive market for base salary and incentive
compensation opportunities for executives of comparably sized companies in
general industry.
The employment agreement with Mr. Higgins provides for an annual base
salary of $590,000, participation in SPR's short-term incentive program, at 65%
of base pay, and participation in SPR's long-term incentive program approved by
shareholders at 140% of base salary. Payments are based on corporate and
personal performance targets established under terms and conditions of the plan.
The agreement also provides that Mr. Higgins will be paid long-term incentives
in accordance with the terms of the plan approved by shareholders in 1994, which
contemplates a performance share grant of 13,200 shares effective January 2001,
to be earned over a three-year period under performance measurements relating to
financial performance and total shareholder return. Effective January 1, 2001,
he also received 104,000 non-qualified stock options, which will vest at
one-third per year. As with the officer group as a whole, the strike price will
be fixed at the average daily closing price of the stock on the New York Stock
Exchange for the 30-day period January 1-31. In
163
addition, Mr. Higgins will be eligible to receive on a pro-rata basis (28 of 36
months) the 2000-2002 performance share grants, which are also earned based on
targets relating to financial performance and total shareholder return. Mr.
Higgins also received a one-time restricted stock grant of 16,000 shares with
dividend equivalents, grossed-up for taxes, which will vest over a four-year
period. Mr. Higgins is required to accumulate and maintain, over five years, two
times annual compensation in SPR stock, and was also granted 400,000
non-qualified stock options at a strike price based on the closing stock price
on the day he accepted employment with SPR, which will vest 25% per year or
sooner if certain price threshold levels are met. Mr. Higgins is also eligible
to participate in SPR's Supplemental Executive Retirement Plan and was provided
credit for all previous years of service with SPR, plus all years served at AGL
Resources or Louisville Gas & Electric, with benefits reduced by any qualified
benefits received from that prior employment. Mr. Higgins was also provided
$2,000,000 of life insurance coverage at SPR expense and is otherwise eligible
to participate in all employer-sponsored health, pension, benefit, and welfare
plans. In the event Mr. Higgins is terminated by SPR for any reason other than
cause (as defined in the agreement), he will receive one year's base salary and
annual incentive payment, subject to execution of an appropriate release and
non-compete covenants. In the event of a termination resulting from a change in
control, within 24 months following a change in control of SPR (as defined in
the agreement either (a) by SPR for reasons other than cause (as defined in the
agreement), (b) death or disability, or (c) by Mr. Higgins for good reason as
defined in the agreement, including a diminution of responsibilities,
compensation, or benefits (unless, with respect to reduction in salary or
benefits, such reduction is applicable to all senior executives of SPR and the
acquirer)), he will receive certain payments and benefits. This severance
payment and benefit include (i) a lump sum payment equal to three times the sum
of his base salary and target bonus, (ii) a lump sum payment equal to the
present value of the benefits he would have received had he continued to
participate in SPR's retirement plans for an additional three years (or, in the
case of SPR's Supplemental Executive Retirement Plan only, the greater of three
years or the period from the date of termination until the executive's early
retirement date, as defined in such plan), and (iii) continuation of life,
disability, accident and health insurance benefits for a period of 36 months
immediately following termination of employment.
Under the employment agreement, SPR will pay any additional amounts
sufficient to hold Mr. Higgins harmless for any excise tax that might be imposed
as a result of being subject to the federal excise tax on "excess parachute
payments" or similar taxes imposed by state or local law in connection with
receiving any compensation or benefits that are considered contingent on a
change in control.
A change in control for purposes of the Employment Agreement occurs (i) if
SPR merges or consolidates, or sells all or substantially all of its assets, and
less than 65% of the voting power of the surviving corporation is owned by those
stockholders who were stockholders of SPR immediately prior to such merger or
sale; (ii) any person acquires 20% or more of SPR's voting stock; (iii) SPR
enters into an agreement or SPR or any person announces an intent to take
action, the consummation of which would otherwise result in a change in control,
or the Board of Directors of SPR adopts a resolution to the effect that a change
in control has occurred; (iv) within a two-year period, a majority of the
directors of SPR at the beginning of such period cease to be directors; or (v)
the stockholders of SPR approve a complete liquidation or dissolution of SPR.
Steven W. Rigazio
On August 31, 2000, SPR entered into an employment agreement with Steven W.
Rigazio, President of Nevada Power. Under the terms of the agreement, Mr.
Rigazio will be paid $255,000 in annual base salary, subject to adjustment if
the Board determines that an adjustment is appropriate. In addition, Mr. Rigazio
is entitled to receive annual incentive and long-term compensation in accordance
with the terms and conditions of existing plans as apply to the officer group as
a whole. If Mr. Rigazio becomes disabled during the course of his employment, he
will be entitled to receive 100% of base salary for six months, and any annual
incentive pay for which he would otherwise be eligible during the year he first
went on disability. At the expiration of any short-term disability, Mr. Rigazio
would be eligible for long-term disability under SPR's long-term disability
164
plan and will continue to be covered by SPR's medical, vision and dental plans
during all of such time and will continue to earn years of service under the
Retirement Plan until age 65 at which time he will be required to retire. During
such time, he will also receive life insurance benefits substantially similar to
those he was entitled to receive before going on short-term disability or
long-term disability. If Mr. Rigazio dies before age 55 (the Retirement Plan's
earliest retirement date), his surviving spouse will be eligible to receive the
Retirement Plan's pre-retirement death benefit at the time Mr. Rigazio would
have become 55. If Mr. Rigazio dies while on short-term disability or long-term
disability, his surviving spouse will be eligible for SERP benefits as if Mr.
Rigazio were 62 and will be paid an annuity on the date of death, or when Mr.
Rigazio would have reached age 55, whichever occurs later. In addition, SPR will
continue to provide the Employee's spouse and eligible dependents all medical
coverage so long as they are not covered by other plans. Mr. Rigazio died on
December 27, 2001, and the payments described above were made.
David G. Barneby
On June 19, 1999, Nevada Power, a wholly owned subsidiary of SPR, entered
into a retention agreement effective on the date of the merger with David G.
Barneby, Vice President, Generation, which provides him with benefits which he
would have been entitled to receive had he voluntarily terminated his original
May 13, 1998, employment agreement with SPR. The agreement provides, in addition
to base pay and any incentive pay or long-term pay accrued during the period of
his employment, an additional $600,890 in cash, payable in substantially equal
quarterly installments commencing on October 1, 1999, and ending on July 31,
2002. If employment is terminated during the term or if the employee dies during
the term, any remaining and unpaid installments shall be paid to the employee or
to his heirs. If the employee is terminated or retires, then the employee shall,
in addition, receive the economic equivalent to an enhancement of his retirement
allowing for payment in cash of the present value of the average early
retirement benefit calculated on the basis of the greater of actual age or age
55, and an additional five years of age or years of service or a combination
thereof to maximize retiree medical benefits. The employee is also entitled to
24 months of employee health and life benefits in amounts substantially
equivalent to those in effect immediately prior to termination. Mr. Barneby
retired on January 1, 2002.
In the event any payments or benefits or distributions thereof under the
contract or any other agreements, policies, or plans of SPR would be subject to
the excise tax imposed by Section 4999 of the Internal Revenue Code by reason of
being considered contingent on a change of control, then the employee is
entitled to receive an additional payment equal to such excise tax.
165
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Financial Statements, Financial Statement Schedules and Exhibits
Page
----
1. Financial Statements:
Independent Auditors' Reports.............................................. 83-84
Consolidated Balance Sheets as of December 31, 2001 and 2000 .............. 85
Consolidated Statements of Income for the Years Ended December 31,
2001, 2000 and 1999 ..................................................... 86
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 2001, 2000 and 1999 ........................................ 87
Consolidated Statements of Common Shareholders' Equity for the Years
Ended December 31, 2001, 2000 and 1999 .................................. 87
Consolidated Statements of Cash Flows for the Years Ended December
31, 2001, 2000 and 1999 ................................................. 88
Consolidated Statements of Capitalization as of December 31, 2001
and 2000 ................................................................ 89-90
Balance Sheets for Nevada Power Company as of December 31, 2001 and
2000 .................................................................... 91
Statements of Income for Nevada Power Company for the Years Ended
December 31, 2001, 2000 and 1999 ........................................ 92
Statements of Cash Flows for Nevada Power Company for the Years Ended
December 31, 2001, 2000 and 1999 ........................................ 93
Statements of Capitalization for Nevada Power Company as of December
31, 2001 and 2000 ....................................................... 94
Consolidated Balance Sheets for Sierra Pacific Power Company as of
December 31, 2001 and 2000 .............................................. 95
Consolidated Statements of Income for Sierra Pacific Power Company
for the Years Ended December 31, 2001, 2000 and 1999 .................... 96
Consolidated Statements of Comprehensive Income for Sierra Pacific Power
Company for the Years Ended December 31, 2001, 2000 and 1999 ............ 97
Consolidated Statements of Common Shareholders' Equity for Sierra
Pacific Power Company for the Years Ended December 31, 2001,
2000 and 1999 ........................................................... 97
Consolidated Statements of Cash Flows for Sierra Pacific Power
Company for the Years Ended December 31, 2001, 2000 and 1999 ............ 98
Consolidated Statements of Capitalization for Sierra Pacific
Power Company as of December 31, 2001 and 2000 .......................... 99
Notes to Financial Statements ............................................. 100
2. Financial Statement Schedules:
Schedule II - Consolidated Valuation and Qualifying Accounts ....... 169-170
166
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 171-189.
(b) Reports on Form 8-K
Form 8-K dated November 16, 2001, filed by SPR - Item 5, Other Events
Disclosed that on November 16, 2001, SPR completed a public offering of
$300,000,000 principal amount of its Premium Income Equity Securities at a price
of $50 per unit with quarterly payments of an initial annual combined rate of
9%.
167
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
March 20, 2002
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 20th day of March, 2002.
/S/ Dennis Schiffel /S/ John Brown
------------------------------------------ ------------------------------------------
Dennis Schiffel John Brown
Senior Vice President, Controller
Chief Financial Officer (Principal Accounting Officer)
(Principal Financial Officer)
/S/ Edward P. Bliss /S/ Jerry E. Herbst
------------------------------------------ ------------------------------------------
Edward P. Bliss Jerry E. Herbst
Director Director
/S/ Mary Lee Coleman /S/ James L. Murphy
------------------------------------------ ------------------------------------------
Mary Lee Coleman James L. Murphy
Director Director
/S/ Krestine M. Corbin /S/ John F. O'Reilly
------------------------------------------ ------------------------------------------
Krestine M. Corbin John F. O'Reilly
Director Director
/S/ Theodore J. Day /S/ Clyde T. Turner
------------------------------------------ ------------------------------------------
Theodore J. Day Clyde T. Turner
Director Director
/S/ James R. Donnelley /S/ Dennis E. Wheeler
------------------------------------------ ------------------------------------------
James R. Donnelley Dennis E. Wheeler
Director Director
/S/ Fred D. Gibson, Jr.
------------------------------------------
Fred D. Gibson, Jr.
Director
168
Sierra Pacific Resources
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2001, 2000 and 1999
(Dollars in Thousands)
Provision for
Uncollectible
Accounts
---------------
Balance at January 1, 1999 $ 5,890
Provision charged to income 7,882
Amounts written off, less recoveries (7,297)
--------------
Balance at December 31, 1999 6,475
Balance at January 1, 2000 6,475
Provision charged to income (1) 14,879
Amounts written off, less recoveries (8,160)
--------------
Balance at December 31, 2000 13,194
==============
Balance at January 1, 2001 13,194
Provision charged to income (2) 42,767
Amounts written off, less recoveries (16,626)
--------------
Balance at December 31, 2001 $ 39,335
==============
Nevada Power Company
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2001, 2000 and 1999
(Dollars in Thousands)
Provision for
Uncollectible
Accounts
---------------
Balance at January 1, 1999 $ 2,429
Provision charged to income 5,877
Amounts written off, less recoveries (5,480)
--------------
Balance at December 31, 1999 2,826
Balance at January 1, 2000 2,826
Provision charged to income (1) 13,090
Amounts written off, less recoveries (4,311)
--------------
Balance at December 31, 2000 11,605
Balance at January 1, 2001 11,605
Provision charged to income (2) 32,137
Amounts written off, less recoveries (12,881)
--------------
Balance at December 31, 2001 $ 30,861
==============
169
Sierra Pacific Power Company
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2001, 2000 and 1999
(Dollars in Thousands)
Provision for
Uncollectible
Accounts
-----------------
Balance at January 1, 1999 $ 3,461
Provision charged to income 2,005
Amounts written off, less recoveries (1,817)
----------
Balance at December 31, 1999 3,649
Balance at January 1, 2000 3,649
Provision charged to income (1) 1,789
Amounts written off, less recoveries (3,849)
----------
Balance at December 31, 2000 1,589
Balance at January 1, 2001 1,589
Provision charged to income (2) 10,630
Amounts written off, less recoveries (3,745)
----------
Balance at December 31, 2001 $ 8,474
==========
(1) Included in the provision charged to income in 2000 was $7.3 million and
$0.3 million, respectively, for NPC and SPPC as reserves against
receivables from California's Power Exchange and Independent System
Operator.
(2) In 2001, the provision charge to income included $12.6 million and $1.2
million respectively, for NPC and SPPC as reserves against receivables
from California's Power Exchange and Independent System Operator. The
provision charge also included $.1 million and $.4 million respectively,
for NPC and SPPC as reserves against receivables from Enron.
170
2001 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 Energy Company, Tuscarora Gas Pipeline 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 Articles of Incorporation of Sierra Pacific Resources
dated July 28, 1999 (filed as Exhibit 3(A) to Form 10-K for year
ended December 31, 1999).
. By-laws of Sierra Pacific Resources as amended through February
25, 2000 (filed as Exhibit 3(A) to Form 10-K for year ended
December 31, 2000).
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 May 19, 1987 (filed as Exhibit (3)(A) to Form 10-K for the
year ended December 31, 1993).
. Certificate of Amendments dated August 26, 1992 to Restated
Articles of Incorporation of Sierra Pacific Power Company dated
May 19, 1987, in connection with Sierra Pacific Power Company's
preferred stock (filed as Exhibit 3.1 to Form 8-K dated August 26,
1992).
. Certificate of Designation, Preferences and Rights dated August
31, 1992 to Restated Articles of Incorporation of Sierra Pacific
Power Company dated May 19, 1987, in connection with Sierra
Pacific Power Company's Class A Series 1 Preferred Stock (filed as
Exhibit 4.3 to Form 8-K dated August 26, 1992).
. 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 Pinon 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 Pinon Pine Investment Co., dated
December 11, 1995 (filed as Exhibit (3)(B) to Form 10-K for the
year ended December 31, 1995).
171
. Agreement of Limited Liability Company of Pinon Pine Company,
L.L.C., dated December 15, 1995, between Pinon Pine Corp., Pinon
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
. Amended and Restated Rights Agreement dated as of February 28,
2001 between Sierra Pacific Resources and Wells Fargo Bank
Minnesota, N.A. as successor Rights Agent (filed as Exhibit 4.1 to
Registration Statement on Form S-3 filed July 2, 2001, File No.
333-64438).
. Purchase and Contract Agreement dated November 16, 2001, between
Sierra Pacific Resources and The Bank of New York, relating to the
Company's Premium Income Equity Securities (PIES) (filed as
Exhibit 4.3 to Form 8-K dated November 16, 2001).
. Corporate PIES Certificate (filed as Exhibit 4.4 to Form 8-K dated
November 16, 2001).
. Treasury PIES Certificate (filed as Exhibit 4.5 to Form 8-K dated
November 16, 2001).
. Pledge Agreement dated November 16, 2001, among Sierra Pacific
Resources, Wells Fargo Bank Minnesota, N.A. and The Bank of New
York (filed as Exhibit 4.6 to Form 8-K dated November 16, 2001).
. Remarketing Agreement dated November 16, 2001, between Sierra
Pacific Resources and Lehman Brothers, Inc. (filed as Exhibit 4.7
to Form 8-K dated November 16, 2001).
. Indenture between Sierra Pacific Resources and The Bank of New
York, dated as of May 1, 2000 for the issuance of debt securities
(filed as Exhibit 4.1 to Form 8-K dated May 22, 2000).
. Global 8-3/4% Note due 2005 (filed as Exhibit 4.2 to Form
8-K dated May 22, 2000).
. Officers' Certificate establishing the terms of the 8-3/4%
Notes due 2005 (filed as Exhibit 4.3 to Form 8-K dated May
22, 2000).
. 7.93% Senior Note due 2007 issued in connection with Sierra
Pacific Resources PIES (filed as Exhibit 4.2 to Form 8-K
dated November 16, 2001).
. Officers' Certificate establishing the terms of the 7.93%
Senior Notes due 2007 (filed as Exhibit 4.3 to Form 8-K
dated November 16, 2001).
. Fiscal and Paying Agency Agreement dated as of April 17,
2000 between Sierra Pacific Resources and Bankers Trust
Company, relating to the Company's money market note
program (filed as Exhibit 4(A) to Form 10-K for the year
ended December 31, 2000).
. Form of Global Floating Rate Note due April 20, 2002 in
connection with the Company's money market note program
(filed as Exhibit 4(B) to Form 10-K for year ended December
31, 2000).
172
. Form of Global Floating Rate Note due April 20, 2003 in
connection with the Company's money market note program
(filed as Exhibit 4(C) to Form 10-K for year ended
December 31, 2000).
Nevada Power Company
. General and Refunding Mortgage Indenture, dated as of 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 4.1(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).
. *(A) Second Supplemental Indenture, dated as of October 1, 2001,
establishing Nevada Power Company's General and Refunding Mortgage
Notes, Floating Rate, Series B, due October 15, 2003.
. *(B) Officer's Certificate establishing the terms of Nevada Power
Company's General and Refunding Mortgage Notes, Floating Rate,
Series B, due October 15, 2003.
. *(C) Form of Nevada Power Company's General and Refunding Mortgage
Notes, Floating Rate, Series B, due October 15, 2003.
. Fiscal and Paying Agency Agreement, dated as of September 19,
2001, between Nevada Power Company and Bankers Trust Company,
relating to the issuance and sale of Nevada Power Company's 6%
Notes due 2003 (filed as Exhibit 4.1 to Form 10-Q for the quarter
ended September 30, 2001).
. Form of Global Note due September 15, 2003, in connection with the
issuance and sale of Nevada Power Company's 6% Notes due 2003
(filed as Exhibit 4.2 to Form 10-Q for the quarter ended September
30, 2001).
. Junior Subordinated Indenture between Nevada Power and IBJ
Schroder Bank & Trust Company, as Debenture Trustee dated March 1,
1997 (filed as Exhibit 4.01 to Form S-3, File No. 333-21091).
. Trust Agreement of NVP Capital I dated March 1, 1997 (filed as
Exhibit 4.03 to Form S-3, File No. 333-21091).
. Form of Amended and Restated Trust Agreement dated March 1, 1997
(filed as Exhibit 4.10 to Form S-3, File No. 333-21091).
173
. Form of Agreement as to Expenses and Liabilities between Nevada
Power and NVP Capital I dated March 1, 1997 (filed as Exhibit
4.14 to Form S-3, File No. 333-21091).
. Form of Preferred Security Certificate for NVP Capital I and NVP
Capital II dated March 1, 1997 (filed as Exhibit 4.11 to Form
S-3, FileNo. 333-21091).
. Form of Guarantee Agreement dated March 1, 1997 (filed as Exhibit
4.12 to Form S-3, File No. 333-21091).
. Form of Supplemental Indenture between Nevada Power and IBJ
Schroder Bank & Trust Company, as Debenture Trustee dated March
1, 1997 (filed as Exhibit 4.13 to Form S-3, File No. 333-21091).
. Supplemental Indenture No. 2 and Assumption Agreement, dated as
of June 1, 1999, between Nevada Power Company and IBJ Whitehall
Bank & Trust Company, supplementing and assuming the Junior
Subordinated Indenture dated as of March 1, 1997 between Nevada
Power Company and IBJ Whitehall Bank & Trust Company (filed as
Exhibit 4(D) to Form 10-K for year ended December 31, 1999).
. Form of Indenture between Nevada Power and IBJ Schroder Bank &
Trust Company, as Trustee dated October 1, 1998 (filed as Exhibit
4.1 to Form S-3, File Nos. 333-63613 and 333-63613-01).
. Certificate of Trust of NVP Capital III dated October 1, 1998
(filed as Exhibit 4.2 to Form S-3, File Nos. 333-63613 and
333-63613-01).
. Trust Agreement for NVP Capital III dated October 1, 1998 (filed
as Exhibit 4.3 to Form S-3, File Nos. 333-63613 and
333-63613-01).
. Form of Amended and Restated Declaration of Trust dated October
1, 1998 (filed as Exhibit 4.4 to Form S-3, File Nos. 333-63613
and 333-63613-01).
. Form of Preferred Security Certificate for NVP Capital III dated
October 1, 1998 (filed as Exhibit 4.5 to Form S-3, File Nos.
333-63613 and 333-63613-01).
. Form of Preferred Securities Guarantee Agreement dated October 1,
1998 (filed as Exhibit 4.7 to Form S-3, File Nos. 333-63613 and
333-63613-01).
. Form of Junior Subordinated Deferrable Interest Debenture dated
October 1, 1998 (filed as Exhibit 4.9 to Form S-3, File Nos.
333-63613 and 333-63613-01).
. Supplemental Indenture No. 1 and Assumption Agreement, dated as
of June 1, 1999, between Nevada Power Company and IBJ Whitehall
Bank & Trust Company, supplementing and assuming the Indenture
dated as of October 1, 1998 between Nevada Power Company and IBJ
Whitehall Bank & Trust Company (filed as Exhibit 4(E) to Form
10-K for year ended December 31, 1999).
. Form of Senior Unsecured Note Indenture between Nevada Power
Company and IBJ Whitehall Bank & Trust Company dated as of March
1, 1999 (filed as Exhibit 4.1 to Form S-4, File No. 333-77325).
174
. Supplemental Indenture No. 1 between Nevada Power Company and IBJ
Whitehall Bank & Trust Company dated as of March 1, 1999 (including
form of 6.20% Senior Unsecured Note, Series A due April 15, 2004)
(filed as Exhibit 4.2 to Form S-4, File No. 333-77325).
. Supplemental Indenture No. 2 between Nevada Power Company and IBJ
Whitehall Bank & Trust Company dated as of April 1, 1999 (including
form of 6.20% Senior Unsecured Note, Series B due April 15, 2004)
(filed as Exhibit 4.3 to Form S-4, File No. 333-77325).
. Supplemental Indenture No. 3 and Assumption Agreement, dated as of
July 1, 1999, between Nevada Power Company and IBJ Whitehall Bank &
Trust Company, supplementing and assuming the Senior Unsecured Note
Indenture dated as of March 1, 1999 between Nevada Power Company and
IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(F) to Form
10-K for year ended December 31, 1999).
. Indenture of Mortgage and Deed of Trust providing for Nevada Power
Company's First Mortgage Bonds, dated as of October 1, 1953 and
Twenty-Eight Supplemental Indentures as follows:
. First Supplemental Indenture, dated as of August 1, 1954 (filed as
Exhibit 4.2 to Form S-1, File No. 2-11440).
. Instrument of Further Assurance dated April 1, 1956 to Indenture
of Mortgage and Deed of Trust dated October 1, 1953 (filed as
Exhibit 4.8 to Form S-1, File No. 2-12666).
. Second Supplemental Indenture, dated as of September 1, 1956 (filed
as Exhibit 4.9 to Form S-1, File No. 2-12566).
. Third Supplemental Indenture, dated as of May 1, 1959 (filed as
Exhibit 4.13 to Form S-1, File No. 2-14949).
. Fourth Supplemental Indenture, dated as of October 1, 1960 (filed as
Exhibit 4.5 to S-1, File No. 2-16968).
. Fifth Supplemental Indenture, dated as of December 1, 1961 (filed as
Exhibit 4.6 to Form S-16, File No. 2-74929).
. Sixth Supplemental Indenture, dated as of October 1, 1963 (filed as
Exhibit 4.6A to Form S-1, File No. 2-21689).
. Seventh Supplemental Indenture, dated as of August 1, 1964 (filed as
Exhibit 4.6B to Form S-1, File No. 2-22560).
. Eighth Supplemental Indenture, dated as of April 1, 1968 (filed as
Exhibit 4.6C to Form S-9, File No. 2-28348.
. Ninth Supplemental Indenture, dated as of October 1, 1969 (filed as
Exhibit 4.6D to Form S-1, File No. 2-34588).
. Tenth Supplemental Indenture, dated as of October 1, 1970 (filed as
Exhibit 4.6E to Form S-7, File No. 2-38314).
175
. Eleventh Supplemental Indenture, dated as of November 1, 1972 (filed
as Exhibit 2.12 to Form S-7, File No. 2-45728).
. Twelfth Supplemental Indenture, dated as of December 1, 1974 (filed
as Exhibit 2.13 to Form S-7, File No. 2-52350).
. Thirteenth Supplemental Indenture, dated as of October 1, 1976
(filed as Exhibit 4.14 to Form S-16, File No. 2-74929).
. Fourteenth Supplemental Indenture, dated as of May 1, 1977 (filed
as Exhibit 4.15 to Form S-16, File No. 2-74929).
. Fifteenth Supplemental Indenture, dated as of September 1, 1978
(filed as Exhibit 4.16 to Form S-16, File No. 2-74929).
. Sixteenth Supplemental Indenture, dated as of December 1, 1981
(filed as Exhibit 4.17 to Form S-16, File No. 2-74929).
. Seventeenth Supplemental Indenture, dated as of August 1, 1982
(filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1982).
. Eighteenth Supplemental Indenture, dated as of November 1, 1986
(filed as Exhibit 4.6 to Form S-3, File No. 33-9537).
. Nineteenth Supplemental Indenture, dated as of October 1, 1989
(filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1989).
. Twentieth Supplemental Indenture, dated as of May 1, 1992 (filed
as Exhibit 4.21 to Form S-3, File No. 33-53034).
. Twenty-First Supplemental Indenture, dated as of June 1, 1992 (filed
as Exhibit 4.22 to Form S-3, File No. 33-53034).
. Twenty-Second Supplemental Indenture, dated as of June 1, 1992
(filed as Exhibit 4.23 to Form S-3, Filed No. 33-53034).
. Twenty-Third Supplemental Indenture, dated as of October 1, 1992
(filed as Exhibit 4.23 to Form S-3, File No. 33-53034).
. Twenty-Fourth Supplemental Indenture, dated as of October 1, 1992
(filed as Exhibit 4.23 to Form S-3, File No. 33-53034).
. Twenty-Fifth Supplemental Indenture, dated as of January 1, 1993
(filed as Exhibit 4.23 to Form S-3, File No. 33-53034).
. Twenty-Sixth Supplemental Indenture, dated as of May 1, 1995
(filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1995).
. Twenty-Seventh Supplemental Indenture dated as of as of July 1,
1999 (filed as Exhibit 4(C) to Form 10-K for year ended December
31, 1999).
176
. *(D) Twenty-Eighth Supplemental Indenture dated as of July 1, 2001.
Sierra Pacific Power Company
. Indenture of Mortgage providing for Sierra Pacific Power Company's First
Mortgage Bonds, dated as of December 1, 1940 (filed as Exhibit 7-A to
Registration No. 2-7475).
. Ninth Supplemental Indenture, dated as of June 1, 1964 (filed as
Exhibit 2-M to Registration No. 2-59509).
. Tenth Supplemental Indenture, dated as of March 31, 1965 (filed
as Exhibit 4-K to Registration No. 2-23932).
. Eleventh Supplemental Indenture, dated as of October 1, 1965
(filed as Exhibit 4-L to Registration No. 2-26552).
. Twelfth Supplemental Indenture, dated as of July 1, 1967 (filed
as Exhibit 4-L to Registration No. 2-36982).
. Sixteenth Supplemental Indenture, dated as of October 1, 1975
(filed as Exhibit 2-Y to Registration No. 2-53404).
. Nineteenth Supplemental Indenture, dated as of April 1, 1978
(filed as Exhibit (4)(A) to the 1991 Form 10-K).
. Twentieth Supplemental Indenture, dated as of October 1, 1978
(filed as Exhibit (4)(B) to the 1991 Form 10-K).
. Twenty-Seventh Supplemental Indenture, dated as of August 1, 1989
(filed as Exhibit (4)(A) to the 1989 Form 10-K).
. Twenty-Eighth Supplemental Indenture, dated as of May 1, 1992
(filed as Exhibit (4)(A) to the 1992 Form 10-K).
. Twenty-Ninth Supplemental Indenture, dated as of June 1, 1992
(filed as Exhibit D to Form 8-K dated July 15, 1992).
. Thirtieth Supplemental Indenture, dated as of July 1, 1992 (filed
as Exhibit (4)(B) to the 1992 Form 10-K).
. Thirty-First Supplemental Indenture, dated as of November 1, 1992
(filed as Exhibit (4)(C) to the 1992 Form 10-K).
. Thirty-Second Supplemental Indenture, dated as of June 1, 1993
(filed as Exhibit 4.6 to Registration No. 33-69550).
. Thirty-Third Supplemental Indenture, dated as of October 1, 1993
(filed as Exhibit C to Form 8-K dated October 20, 1993).
. Thirty-Fourth Supplemental Indenture, dated as of February 1,
1996 (filed as Exhibit C to Form 8-K dated March 11, 1996).
177
. Thirty-Fifth Supplemental Indenture, dated as of February 1, 1997
(filed as Exhibit C to Form 8-K dated March 10, 1997).
. 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
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).
. Collateral Trust Indenture dated June 1, 1992 between Sierra Pacific Power
Company and Bankers Trust Company, as Trustee, relating to Sierra Pacific
Power Company's medium-term note program (filed as Exhibit B to Form 8-K
dated July 15, 1992).
. First Supplemental Indenture dated June 1, 1992 (filed as Exhibit C to
Form 8-K dated July 15, 1992).
. Second Supplemental Indenture dated October 1, 1993 (filed as Exhibit
B to Form 8-K dated October 20, 1993).
. Third Supplemental Indenture dated as of February 1, 1996 (filed as
Exhibit B to Form 8-K dated March 11, 1996).
. Fourth Supplemental Indenture dated as of February 1, 1997 (filed as
Exhibit B to Form 8-K dated March 10, 1997).
. Form of Medium-Term Global Fixed Rate Note, Series A in connection
with Sierra Pacific Power Company's medium-term note program (filed as
Exhibit E to Form 8-K dated July 15, 1992 ).
. Form of Medium-Term Global Fixed Rate Note, Series B in connection
with Sierra Pacific Power Company's medium-term note program (filed as
Exhibit D to Form 8-K dated October 25, 1993).
. Form of Medium-Term Global Fixed-Rate Note, Series C in connection
with Sierra Pacific Power Company's medium-term note program (filed as
Exhibit D to Form 8-K dated March 11, 1996).
. Form of Medium-Term Global Fixed-Rate Note, Series D in connection
with Sierra Pacific Power Company's medium-term note program (filed as
Exhibit D to Form 8-K dated March 10, 1997).
178
(10) Sierra Pacific Resources, Nevada Power Company, and Sierra Pacific
Power Company
Sierra Pacific Resources
. *(A) Credit Agreement dated as of November 30, 2001, among
Sierra Pacific Resources, Union Bank of California, N.A., as
Sole Bookrunner and Administrative Agent, Wells Fargo Bank,
N4.A., as Syndication Agent, Bank One, NA, BNP Paribas and
Mellon Bank, N.A., as Co-Documentation Agents, the Lenders
party hereto from time to time, and Union Bank of California,
N.A. and Wells Fargo Bank, N.A., as Co-Lead Arrangers relating
to $75,000,000 credit facility.
. *(B) Change in Control Agreement dated May 21, 2001, by and
between Sierra Pacific Resources and Walter M. Higgins.
. Walter M. Higgins Employment Letter dated August 4, 2000
(filed as Exhibit 10(B) to Form 10-K for the year ended
December 31, 2000).
. *(C) Change in Control Agreement dated May 21, 2001, by and
among Sierra Pacific Resources and the following officers
(individually): Jeffrey L. Ceccarelli, Steven C. Oldham,
Victor H. Pena, William E. Peterson and Mark A. Ruelle 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.
. *(D) Change in Control Agreement dated May 21, 2001, by and
among Sierra Pacific Resources and the following officers
(individually): Richard K. Atkinson, Susan Brennan, Matt H.
Davis, Carol Elmore, Paul Heagen, Douglas R. Ponn, Mary O.
Simmons and Mike Smart, 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.
. Sierra Pacific Resources' Executive Long-Term Incentive Plan
(filed as Exhibit 99.1 to Form S-8 dated December 13, 1999).
. 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
. Asset Sale Agreement between Nevada Power Company and The AES
Corporation dated as of May 10, 2000 for the Mohave Asset
Bundle (filed as Exhibit (10)(C) to Form 10-K for the year
ended December 31, 2000).
. Transitional Power Purchase Agreement by and between Nevada
Power Company and AES Mohave, LLC dated as of May 10, 2000
(filed as Exhibit (10)(D) to Form 10-K for the year ended
December 31, 2000).
. Asset Sale Agreement between Nevada Power Company, NRG Energy,
Inc. and Dynegy Holdings Inc. for the Clark Asset Bundle dated
as of November 16, 2000 (filed as Exhibit (10)(E) to Form 10-K
for the year ended December 31, 2000).
179
. Transitional Power Purchase Agreement by and between Nevada
Power Company and Clark Power LLC dated as of November 16,
2000 (filed as Exhibit (10)(F) to Form 10-K for the year ended
December 31, 2000).
. Asset Sale Agreement between Nevada Power Company, NRG Energy,
Inc. and Dynegy Holdings Inc. for the Reid Gardner Asset
Bundle dated as of November 16, 2000 (filed as Exhibit (10)(G)
to Form 10-K for the year ended December 31, 2000).
. Transitional Power Purchase Agreement by and between Nevada
Power Company and Reid Gardner Power LLC dated as of November
16, 2000 (filed as Exhibit (10)(H) to Form 10-K for the year
ended December 31, 2000).
. Asset Sale Agreement between Nevada Power Company and Pinnacle
West Energy Corporation for the Harry Allen Asset Bundle,
dated as of December 1, 2000 (filed as Exhibit (10)(I) to Form
10-K for the year ended December 31, 2000).
. Transitional Power Purchase Agreement by and between Nevada
Power Company and Pinnacle West Energy Corporation dated as of
December 1, 2000 (filed as Exhibit (10)(J) to Form 10-K for
the year ended December 31, 2000).
. Asset Sale Agreement between Nevada Power Company and Reliant
Energy Sunrise, LLC for the Sunrise/Sun-Peak Asset Bundle
dated as of December 9, 2000 (filed as Exhibit (10)(K) to Form
10-K for the year ended December 31, 2000).
. Transitional Power Purchase Agreement by and between Nevada
Power Company and Reliant Energy Sunrise, LLC dated as of
December 9, 2000 (filed as Exhibit (10)(L) to Form 10-K for
the year ended December 31, 2000).
. *(E) Credit Agreement, dated as of November 1, 2001, among
Nevada Power Company, Union Bank of California, N.A., as Sole
Bookrunner and Administrative Agent, Wells Fargo Bank, N.A.,
as Syndication Agent, Bank One, NA, BNP Paribas and
Mellon Bank, N.A., as Co-Documentation Agents, the Lenders
party hereto from time to time, and Union Bank of California,
N.A. and Wells Fargo Bank, N.A., as Co-Lead Arrangers relating
to $200,000,000 credit facility.
. Letter of Credit and Reimbursement Agreement dated as of
October 1, 1995 among Nevada Power Company, The Banks named
therein, and Societe Generale, Los Angeles Branch (relating to
the Clark County, Nevada $85,000,000 Industrial Development
Refunding Revenue Bonds, Series 1995B; Clark County, Nevada
$20,300,000 Pollution Control Refunding Revenue Bonds Series,
1995D; and Coconino County, Arizona Pollution Control
Corporation $13,000,000 Pollution Control Refunding Revenue
Bonds, Series 1995E) (filed as Exhibit 10.80 to Form 10-K,
File No. 1-4698, Year 1995).
. Letter of Credit and Reimbursement Agreement dated as of
October 1, 1995 among Nevada Power Company, The Banks named
therein, and Barclays Bank PLC, New York Branch (relating to
Clark County, Nevada $44,000,000 Industrial Development
Refunding Revenue Bonds, Series 1995C) (filed as Exhibit 10.81
to Form 10-K, File No. 1-4698, Year 1995).
. Letter of Credit and Reimbursement Agreement dated as of April
12, 1994 between Nevada Power Company and Societe Generale,
Los Angeles Branch and Amendment No. 1 thereto dated as of May
3, 1994 (relating to $60,000,000 Clark County, Nevada
Floating Rate Weekly
180
Demand Industrial Development Revenue Bonds, Series 1989A)
(filed as Exhibit 10.72 to Form 10-K, File No. 1-4698, Year
1994).
. Reimbursement Agreement dated as of November 1, 1988 between
the Fuji Bank, Limited and Nevada Power Company (relating to
$25,000,000 Clark County, Nevada Floating Rate Weekly Demand
Industrial Development Revenue Bonds, Series 1998) (filed as
Exhibit 10.43 to Form 10-K, File No. 1-4698, Year 1988).
. Reimbursement Agreement dated as of December 1, 1985 between
The Fuji Bank, Limited and Nevada Power Company (relating to
Clark County, Nevada $44,000,000 Floating Rate Weekly Demand
Industrial Development Revenue Bonds, Series 1985) (filed as
Exhibit 10.38 to Form 10-K, File No. 1-4698, Year 1986).
. Guaranty Agreement dated as of March 1, 1974 between Nevada
Power Company and Commerce Union Bank as Trustee (filed as
Exhibit 5.39 to Form 8-K, File No. 1-4698, April 1974).
. Financing Agreement No. 1 between Clark County, Nevada and
Nevada Power Company dated as of June 1, 2000 (Series 2000A)
(filed as Exhibit 10(O) to Form 10-K for the year ended
December 31, 2000).
. Financing Agreement No. 2 between Clark County, Nevada and
Nevada Power Company dated as of June 1, 2000 (Series 2000B)
(filed as Exhibit 10(P) to Form 10-K for the year ended
December 31, 2000).
. 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, Year 1997).
. Financing Agreement between Coconino County, Arizona Pollution
Control Corporation and Nevada Power Company dated November 1,
1997 (relating to Coconino County, Arizona $20,000,000
Pollution Control Corporation Pollution Control Revenue Bonds,
Series 1997B) (filed as Exhibit 10.84 to Form 10-K, File No.
1-4698, Year 1997).
. Financing Agreement between Coconino County, Arizona Pollution
Control Corporation and Nevada Power Company dated October 1,
1996 (relating to Coconino County, Arizona Pollution Control
Corporation $20,000,000 Pollution Control Revenue Bonds,
Series 1996) (filed as Exhibit 10.82 to Form 10-K, File
1-4698, Year 1996).
. 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, Year 1995).
. 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, Year 1995).
181
. 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
x 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-4698,
Year 1995).
. 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, Year
1995).
. Financing Agreement between Coconino County, Arizona Pollution\
Control Corporation and Nevada Power Company dated October 1, 1995
(relating to Coconino County, Arizona Pollution Control Corporation
$13,000,000 Pollution Control Refunding Revenue Bonds, Series
1995E) (filed as Exhibit 10.79 to Form 10-K, File No. 1-4698, Year
1995).
. 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, Year 1992).
. 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, Year 1992).
. Financing Agreement between Clark County, Nevada and Nevada Power
Company dated June 1, 1992 (Relating to Pollution Control Refunding
Revenue Bonds, Series 1992B) (filed as Exhibit 10.66 to Form 10-K,
File No. 1-4698, Year 1992).
. Financing Agreement between Clark County, Nevada and Nevada Power
Company dated as of November 1, 1988 (relating to Clark County,
Nevada $25,000,000 Floating Rate Weekly Demand Industrial
Development Revenue Bonds, Series 1988) (filed as Exhibit 10.42 to
Form 10-K, File No. 1-4698, Year 1988).
. Financing Agreement between Clark County, Nevada and Nevada Power
Company dated as of December 1, 1985 (relating to Clark County,
Nevada $44,000,000 Floating Rate Weekly Demand Industrial
Development Revenue Bonds, Series 1985) (filed as Exhibit 10.37 to
Form 10-K, File No. 1-4698, Year 1985).
. Financing Agreement dated as of February 1, 1983 between Clark
County, Nevada and Nevada Power Company (relating to Clark ounty,
Nevada $78,000,000 Industrial Development Revenue Bonds, Series
1983) (filed as Exhibit 10.36 to Form 10-K, File No. 1-4698, Year
1985).
. Plant Collective Bargaining Agreement dated February 1, 1998,
effective through February 1, 2002 between Nevada Power Company and
the International Brotherhood of Electrical Workers Local No. 396
(filed as Exhibit 10(Q) to Form 10-K for the year ended December
31, 2000).
. Clerical Collective Bargaining Agreement dated February 1, 1998,
effective through February 1, 2002 between Nevada Power Company and
the International Brotherhood of Electrical Workers Local No. 396
(filed as Exhibit 10(R) to Form 10-K for the year ended December
31, 2000).
182
. Generation Agreement dated as of June 25, 1999 between Nevada Power
Company and the International Brotherhood of Electrical Workers Local
No. 396 (filed as Exhibit 10(S) to Form 10-K for the year ended
December 31, 2000).
. Contract for Long-Term Power Purchases from Qualifying Facilities
dated May 27, 1992 between Las Vegas Co-generation, Inc. and Nevada
Power Company (filed as Exhibit 10.70 to Form 10-K, File No. 1-4698,
Year 1993).
. *(F) Western Systems Power Pool ("WSPP") Agreement effective March 1,
2002 between Nevada Power Company as a member of WSPP and the other
members of the WSPP.
. Contract A for Long-Term Power Purchases from Qualifying Facilities
dated May 2, 1989 between Nevada Cogenerational Associates #1
(assigned from Bonneville Nevada Corporation) and Nevada Power
Company (filed as Exhibit 10.47 to Form 10-K, File No. 1-4698, Year
1989).
. Contract B for Long-Term Power Purchases from a Qualifying Facility
dated May 24, 1990 between Nevada Cogenerational Associates (assigned
from Bonneville Nevada Corporation) and Nevada Power Company (filed
as Exhibit 10.56 to Form 10-K, File No. 1-4698, Year 1990).
. Contract for Long-Term Power Purchases from Qualifying Facilities
dated April 10, 1989 between Saguaro Power Company (assigned from
Magna Energy Systems and Eastern Sierra Energy Company) and Nevada
Power Company (filed as Exhibit 10.48 to Form 10-K, File No. 1-4698,
Year 1989).
. Agreement for Transmission Service dated March 29, 1989 between
Overton Power District No. 5, Lincoln County Power District No. 1 and
Nevada Power Company (filed as Exhibit 10.51 to Form 10-K, File No.
1-4698, Year 1989).
. Contract for Operation, Maintenance, Replacement, Ownership, and
Interconnection of Facilities dated June 30, 1988 between United
States Department of Energy Western Area Power Administration and
Nevada Power Company (filed as Exhibit 10.52 to Form 10-K, File No.
1-4698, Year 1989).
. Transmission Facilities Agreement between Utah Power & Light Company
and Nevada Power Company, dated August 17, 1987 (filed as Exhibit
10.41 to Form 10-K, File No. 1-4698, Year 1987).
. 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, Year 1987).
. 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).
. 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).
. 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
183
of Los Angeles, Salt River Project Agricultural Improvement and Power
District and the Peabody Coal Company (filed as Exhibit 5.35 to Form
S-7, File No. 2-56356).
. 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).
. 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).
. 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).
. 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).
. 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).
. Reliability Management System Agreement dated June 18, 1999 by and
between Western Systems Coordinating Council and Nevada Power Company
(filed as Exhibit 10(U) to Form 10-K for the year ended December 31,
2000).
. *(G) Service Agreement No. 90 for Long-Term Firm Point-To-Point
Transmission Service filed with the Federal Energy Regulatory
Commission July 20, 2001 between Nevada Power Company and Reliant
Energy Services, Inc.
. *(H) Service Agreement Nos. 95 and 96 for Long-Term Firm
Point-To-Point Transmission Service filed with the Federal Energy
Regulatory Commission August 1, 2001 between Nevada Power Company and
Calpine Corporation.
. *(I) Service Agreement No. 97 for Long-Term Firm Point-To-Point
Transmission Service filed with the Federal Energy Regulatory
Commission August 1, 2001 between Nevada Power Company and Duke
Energy Trading and Marketing.
. *(J) Service Agreement Nos. 98 and 99 for Long-Term Firm
Point-To-Point Transmission Service filed with the Federal Energy
Regulatory Commission August 1, 2001 between Nevada Power Company and
Mirant Americas Development, Inc.
184
. *(K) Service Agreement No. 100 for Long-Term Firm Point-To-Point
Transmission Service filed with the Federal Energy Regulatory
Commission August 1, 2001 between Nevada Power Company and Pinnacle
West Energy Company.
. *(L) Service Agreement No. 101 for Long-Term Firm Point-To-Point
Transmission Service filed with the Federal Energy Regulatory
Commission August 1, 2001 between Nevada Power Company and Reliant
Energy Services, Inc.
. *(M) Service Agreement No. 102 for Long-Term Firm Point-To-Point
Transmission Service filed with the Federal Energy Regulatory
Commission August 3, 2001 between Nevada Power Company and Las Vegas
Cogeneration II, LLC.
. 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, Year 1983).
Sierra Pacific Power Company
. Asset Sale Agreement between Sierra Pacific Power Company and NRG
Energy, Inc. dated as of October 16, 2000 for the North Valmy Asset
Bundle (filed as Exhibit (10)(V) to Form 10-K for the year ended
December 31, 2000).
. Transitional Power Purchase Agreement by and between Sierra Pacific
Power Company and Valmy Power LLC dated as of October 16, 2000 (filed
as Exhibit (10)(W) to Form 10-K for the year ended December 31,
2000).
. Asset Sale Agreement between Sierra Pacific Power Company and WPS
Northern Nevada, LLC for the Tracy/Pinon Asset Bundle dated as of
October 25, 2000 (filed as Exhibit (10)(X) to Form 10-K for the year
ended December 31, 2000).
. Transitional Power Purchase Agreement by and between Sierra Pacific
Power Company and WPS Northern Nevada, LLC dated as of October 25,
2000 (filed as Exhibit (10)(Y) to Form 10-K for the year ended
December 31, 2000).
. Asset Purchase Agreement between Sierra Pacific Power Company and
Truckee Meadows Water Authority dated as of January 15, 2001 (filed
as Exhibit (10)(Z) to Form 10-K for the year ended December 31,
2000).
. *(N) Credit Agreement dated as of November 30, 2001, among Sierra
Pacific Power Company, Union Bank of California, N.A., as Sole
Bookrunner and Administrative Agent, Wells Fargo Bank, N.A., as
Syndication Agent, Bank One, NA, BNP Paribas and Mellon Bank, N.A.,
as Co-Documentation Agents, the Lenders party hereto from time to
time, and Union Bank of California, N.A. and Wells Fargo Bank, N.A.,
as Co-Lead Arrangers relating to $150,000,000 credit facility.
. Financing Agreement dated June 1, 1993 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 1993A (filed as Exhibit (10) (I) to Form 10-K
for the year ended December 31, 1993).
185
. Financing Agreement dated June 1, 1993 between Sierra Pacific Power
Company and Washoe County, Nevada relating to the Washoe County,
Nevada Gas and Water Facilities Refunding Revenue Bonds (Sierra
Pacific Power Company Project) Series 1993B (filed as Exhibit (10)
(J) to Form 10-K for the year ended December 31, 1993).
. *(O) 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.
. Financing Agreement dated September 1, 1990 between Sierra Pacific
Power Company and Washoe County, Nevada relating to the Washoe
County, Nevada Gas Facilities Revenue Bonds (Sierra Pacific Power
Company Project) Series 1990 (filed as Exhibit (10)(C) to Form 10-K
for the year ended December 31, 1990).
. Financing Agreement dated December 1, 1987 between Sierra Pacific
Power Company and Washoe County, Nevada relating to the Washoe
County, Nevada Variable Rate Demand Gas Facilities Revenue Bonds
(Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit
(10)(H) to Form 10-K for the year ended December 31, 1993).
. Financing Agreement dated June 1, 1987 between Sierra Pacific Power
Company and Washoe County, Nevada relating to the Washoe County,
Nevada Variable Rate Demand Water Facilities Revenue Bonds (Sierra
Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(G)
to Form 10-K for the year ended December 31, 1993).
. Financing Agreement dated March 1, 1987 between Sierra Pacific Power
Company and Humboldt County, Nevada relating to the Humboldt County,
Nevada Variable Rate Demand Pollution Control Refunding Revenue Bonds
(Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit
(10)(E) to Form 10-K for the year ended December 31, 1993).
. Financing Agreement dated March 1, 1987 between Sierra Pacific Power
Company and Washoe County, Nevada relating to the Washoe County,
Nevada Variable Rate Demand Gas and Water Facilities Refunding
Revenue Bonds (Sierra Pacific Power Company Project) Series 1987
(filed as Exhibit (10)(F) to Form 10-K for the year ended December
31, 1993).
. Agreement dated January 1, 1998 (extended through December 31, 2002)
between Sierra Pacific Power Company and the International
Brotherhood of Electrical Workers Local No. 1245 (filed as Exhibit
10(B) to Form 10-K for the year ended December 31, 1997).
. 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).
. 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).
. 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) to Form 10-K for the year ended December 31, 1999).
186
. Cooperative Agreement dated July 31, 1992 between Sierra Pacific
Power Company and the United States Department of Energy in
connection with the Pinon Pine Integrated Coal Gasification Combined
Cycle Project (filed as Exhibit (10)(H) to Form 10-K for the year
ended December 31, 1992).
. 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).
. Western Systems Power Pool ("WSPP") Agreement effective March 1, 2002
between Sierra Pacific Power Company as a member of WSPP and the
other members of the WSPP (filed as Exhibit (10)(F) above).
. General Transfer Agreement dated February 25, 1988 between Sierra
Pacific Power Company and the United States of America Department of
Energy acting by and through the Bonneville Power Administration
(filed as Exhibit (10)(E) to Form 10-K for the year ended December
31, 1988).
. *(P) Amendatory Agreement No. 1 dated April 11, 1995 to General
Transfer Agreement dated February 25, 1988 between Sierra Pacific
Power Company and the United States of America Department of Energy
acting by and through the Bonneville Power Administration.
. *(Q) Amendatory Agreement No. 2 dated July 5, 2000 to General
Transfer Agreement dated February 25, 1988 between Sierra Pacific
Power Company and the United States of America Department of Energy
acting by and through the Bonneville Power Administration.
. *(R) Coal Sales Agreement dated January 1, 2002 between Sierra
Pacific Power Company and Arch Coal Sales Company, Inc. (5 year term
ending on December 31, 2006).
. Coal Purchase Contract dated June 19, 1986 between Sierra Pacific
Power Company, Black Butte Coal Company and Idaho Power Company
(filed as Exhibit (10)(C) to the Form 10-K for the year ended
December 31, 1992).
. Interconnection Agreement dated May 29, 1981 between Sierra Pacific
Power Company and Idaho Power Company (filed as Exhibit (10)(C) to
Form 10-K for the year ended December 31, 1991).
. Amendatory Agreement dated February 14, 1992 to Interconnection
Agreement dated May 29, 1981 between Sierra Pacific Power Company and
Idaho Power Company (filed as Exhibit (10)(D) to Form 10-K for the
year ended December 31, 1991).
. Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power
Company and Coastal States Energy Company (confidential portions
omitted and filed separately with the Securities and Exchange
Commission) (filed as Exhibit 5-GG to Registration No. 2-62476).
. 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).
. Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement dated
May 16, 1978 between Sierra Pacific Power Company and Coastal States
Energy Company (filed as Exhibit (10)(A) to Form 10-K for the year
ended December 31, 1993).
187
. 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).
. 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).
. 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).
(11) Nevada Power Company and Sierra Pacific Power Company
. 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
. *(A) Statement regarding computation of Ratios of Earnings to Fixed
Charges.
Nevada Power Company
. *(B) Statement regarding computation of Ratios of Earnings to Fixed
Charges.
Sierra Pacific Power Company
. *(C) Statement regarding computation of Ratios of Earnings to Fixed
Charges.
(21) Sierra Pacific Resources
. Nevada Power Company, a Nevada Corporation.
Sierra Pacific Power Company, a Nevada Corporation.
Great Basin Energy Company, a Nevada Corporation.
Lands of Sierra, Inc., a Nevada Corporation.
Nevada Electric Investment Company, a Nevada Corporation.
Sierra Energy Company dba e.three, a Nevada Corporation.
Sierra Gas Holdings Company, a Nevada Corporation.
Sierra Pacific Energy Company, a Nevada Corporation.
Sierra Pacific Resources Capital Trust I, a Delaware Business
Trust.
Sierra Pacific Resources Capital Trust II, a Delaware Business
Trust.
Sierra Water Development Company, a Nevada Corporation.
Tuscarora Gas Pipeline Company, a Nevada Corporation.
Tuscarora Gas Operating Company, a Nevada Corporation.
188
Nevada Power Company
. Commonsite, Inc., a Nevada Corporation.
NVP Capital I, a Delaware Business Trust.
NVP Capital II, a Delaware Business Trust.
Sierra Pacific Power Company
. Pinon Pine Company, a Nevada Corporation.
Pinon Pine Investment Company, a Nevada Corporation.
Pinon Pine Investment Co. LLC, a Nevada Limited Liability Company.
GPSF-B, a Delaware Corporation.
SPPC Funding LLC, a Delaware Limited Liability Company.
Sierra Pacific Power Capital Trust I, a Delaware Business Trust.
(23) Sierra Pacific Resources
. *(A) Consent of Independent Accountants in connection with the
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 Forms S-8, and No.
333-72160 (Post-Effective Amendment to Registration No. 333-80149
on Form S-3.
189