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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, 1998 Commission File Number 0-508
SIERRA PACIFIC POWER COMPANY
(Exact name of registrant as specified in its charter)
NEVADA 88-0044418
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
P.O. Box 10100 (6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(Address of principal executive office) (Zip Code)
(775) 834-4011
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: none.
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock: Series A, $2.44 Dividend, $50 par value
--------------- Series B, $2.36 Dividend, $50 par value
(Title of Class) Series C, $3.90 Dividend, $50 par value
Sierra Pacific Power Capital Trust I, $2.15 Dividend,
$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
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State the aggregate market value of the voting stock held by non-affiliates. As
of March 16, 1999: None
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date.
Class Outstanding at March 16, 1999: 1,000 shares
Common Stock, $3.75 par value
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SIERRA PACIFIC POWER COMPANY
1998 ANNUAL REPORT FORM 10-K
CONTENTS
<TABLE>
<CAPTION>
<S> <C>
PART I............................................................................................3
ITEM 1. BUSINESS.................................................................................3
SIERRA PACIFIC POWER COMPANY (1)...............................................................3
BUSINESS OUTLOOK AND OVERVIEW (1)..............................................................4
MAJOR PROJECTS SUMMARY........................................................................10
NATURAL GAS BUSINESS..........................................................................18
ITEM 2. PROPERTIES.............................................................................26
ITEM 3. LEGAL PROCEEDINGS......................................................................27
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS....................................27
PART II..........................................................................................28
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS...............28
ITEM 6. SELECTED FINANCIAL DATA................................................................29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.............................................................................29
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.............................45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS....................................................53
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES............................................................................73
PART III.........................................................................................74
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS......................................................74
ITEM 11. EXECUTIVE COMPENSATION................................................................79
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND...................................85
MANAGEMENT............................................................................85
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........................................86
PART IV..........................................................................................89
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.......................89
Appendix E....................................................................................24
</TABLE>
2
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PART I
ITEM 1. BUSINESS
SIERRA PACIFIC POWER COMPANY (1)
Sierra Pacific Power Company, hereinafter known as the Company or SPPC, is a
Nevada corporation organized in 1965 as a successor to a Maine corporation
organized in 1912. The Company became a wholly- owned subsidiary of Sierra
Pacific Resources (SPR) on May 31, 1984. Its mailing address is Post Office Box
10100 (6100 Neil Road), Reno, Nevada 89520-0400.
The Company has four primary subsidiaries: Pinon Pine Corp. (PPC), Pinon
Pine Investment Co. (PPIC), GPSF-B, and Sierra Pacific Power Capital I (the
Trust). PPC and PPIC own 25% and 75% of a 38% interest in Pinon Pine Company,
L.L.C. GPSF-B, a Delaware corporation formally owned by General Electric
Capital Corporation and now owned by the Company, owns the remaining 62%. 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 (S)
29 of the Internal Revenue Code. The Capital Trust was created to issue trust
securities in order to purchase the Company's junior subordinated debentures.
The Company is a public utility primarily engaged in the distribution,
transmission, generation, purchase and sale of electric energy. It provides
electricity to approximately 294,000 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. In 1998, electric revenue was 79.8% of total revenue.
The Company also provides natural gas in Nevada to approximately 105,000
customers in an area of about 600 square miles in Reno/Sparks and environs. It
supplies water service in Nevada to about 67,000 customers in the Reno/Sparks
metropolitan area. Natural gas revenues were 13.6% and water revenues were 6.6%
of total revenues.
The Company used diverse resources to meet its 1998 electric energy
requirements, including gas and oil generation (32.8%), coal generation (21.0%),
hydroelectric generation (0.6%), and purchased power (45.6%). The Company has
no ownership interest in, nor does it operate any nuclear generating units.
In 1998, the Company's electric customer count grew by 2.4%; its natural gas
customer count increased by 4.0%; and its water customer count increased by
3.0%. Many factors account for this growth, not the least of which are
favorable business and tax climates.
The Company had 1,446 regular employees as of December 31, 1998, down 1.8%
from 1997. The Company's current contract with the International Brotherhood of
Electrical Workers, which represents 58.0% of the workforce, was renegotiated in
1997 and is in effect until December 31, 2000. The three-year contract provides
for a 2.75% general wage increase for most bargaining unit employees beginning
January 1, 1998, with 2.75% increases in both 1999 and 2000. In addition, the
contract provides for bargaining unit employees to participate in the incentive
compensation program. Nevada is a "right-to-work" state.
For a discussion of results of operations refer to Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations.
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(1) 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 which 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 SPPC's actual results to differ
materially from those contemplated in any forward-looking statement
include, among others, the following: (1) the pace and extent of the
ongoing restructuring of the electric and gas industries in Nevada and
California; (2) the outcome of regulatory and legislative proceedings and
operational changes related to industry restructuring; (3) the amount SPPC
is allowed to recover from its customers for certain costs which prove to
be uneconomic in the new competitive market; (4) regulatory delays or
conditions imposed by regulatory bodies in approving the merger of SPR with
Nevada Power Company; (5) the outcome of ongoing and future regulatory
proceedings; (6) management's ability to integrate the operations of SPPC
and Nevada Power Company and to implement and realize anticipated cost
savings from the Merger; (7) industrial, commercial and residential growth
in the service territory of SPPC; (8) fluctuations in electric, gas and
other commodity prices and the ability to manage such fluctuations
successfully; (9) changes in the capital markets and interest rates
affecting the ability to finance capital requirements; (10) the loss of any
significant customers; (11) the ability to lessen the risk of the impact of
the Year 2000 on internal and external computer and software systems; and
(12) the weather and other natural phenomena. 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. SPPC assumes no
obligation to update forward-looking statements to reflect actual results,
changes in assumptions or changes in other factors affecting forward-
looking statements.
BUSINESS OUTLOOK AND OVERVIEW (1)
General Electric Industry Trends
In April 1998, SPR announced a merger with Nevada Power Company. This
"merger of equals" combines the two investor-owned utilities in Nevada, the
fastest growing state in the United States. The merger will allow the companies
to operate more efficiently and to better compete in the new utility
environment. See Merger Discussion for more details.
-----------------
As a comparison, 19 other mergers of electric and/or gas companies were
announced, pending or completed in 1998. Some of the largest national and
international utilities announced mergers in 1998, including PacifiCorp &
Scottish Power, New England Electric System & National Grid Group, and CalEnergy
& MidAmerica Energy Holdings. A third Nevada utility is also involved in a
merger with the December 14, 1998 announcement of ONEOK's offer and Southern
Union's counteroffer to acquire Southwest Gas Corp. of Las Vegas. Merger and
acquisition activity is expected to continue into the next decade, as companies
position for continued electric restructuring throughout the United States.
4
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Federal and state legislation is moving the electric utility industry
toward competition. Federal and state regulators play critical roles in
establishing a competitive marketplace. Currently, 13 states have passed
restructuring bills, and 21 more states are considering legislation to
restructure their electric markets. In addition, the U.S. Congress is
considering national legislation that would implement electric restructuring
across the nation. Passage of a comprehensive federal bill is expected within
the next several years. Regulatory changes generally focus on the unbundling of
utility functions into separate products and services. The two major products
and services are energy (e.g. kilowatt hours) and the delivery of that energy
(e.g. transmission and distribution). Other services such as meter reading and
billing may also be opened to competition.
The Federal Energy Regulatory Commission (FERC) is considering the
potential for Regional Transmission Organizations (RTO's). RTO's which can take
the form of independent system operators or independent transmission companies,
are independent organizations that oversee the operation of electric power lines
on a regional scale. FERC orders 888/889 passed in 1996, implemented open
access tariffs that allowed multiple users to access transmission systems
without discrimination. Some solutions to open transmission access and multiple
rates (pancaked rates) across short distances have been discussed by the FERC
for several years. FERC has conducted meetings around the country to explore
the possibility of requiring utilities to participate in RTO's as wholesale
power markets are opened to competition. A notice of proposed ruling (NOPR) is
expected in 1999.
The Company is subject to California, Nevada and FERC regulatory
jurisdiction. Federal and state regulation will continue to play an active role
in the Company's utility business. The Company's electric system demand exceeds
the import capabilities of its transmission system. As such, a yet-to-be
determined amount of the Company's generation capacity may be identified as
"must run" at the time the plants are sold (a condition of the merger) or open
access is available to new customers. The output of "must run" facilities may
continue to be price regulated by FERC after the deregulation of generation (see
Generation Divestiture). FERC will also regulate the Company's electric
- ----------------------
transmission system. The states will continue to regulate those retail
distribution services determined to be non-competitive.
Approximately 69% of SPPC's operating revenues are related to electric
sales in Nevada. Nevada passed Assembly Bill 366 (AB366) in July 1997.
Pursuant to AB366, the Public Utilities Commission of Nevada (PUCN) authorizes
customers to obtain competitive services from alternative sellers starting no
later than December 31, 1999, unless the PUCN or the state legislature
determines a different date better serves the public interest. AB366 allows the
PUCN to authorize full recovery of costs that it determines to be stranded as a
result of restructuring. In August 1997, the PUCN opened an investigatory
docket of the issues to be considered as a result of restructuring the electric
industry. The Company is a participant in this docket. Issues being addressed
include:
. Definition of noncompetitive services
. Unbundling of costs among distribution, transmission, generation components
of the electric business
. Stranded costs
. Affiliate rules
. Other actions needed to proceed from regulation to fully competitive energy
markets
See Nevada Matters for more details on the Company's response to this
--------------
restructuring process.
California accounts for about 5% of the Company's electric revenue.
California required all investor-owned utilities, including SPPC, to offer
customers direct access beginning March 31, 1998, and required a
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10% rate reduction for all residential and small commercial customers effective
January 1, 1998. California customers may choose to continue to take service
from their incumbent utility at tariff rates, purchase energy from marketers or
contract directly with a generator. Any customers choosing to purchase energy
from marketers or generators will pay a distribution fee for their use of the
Company's transmission and distribution systems. Operating results should not be
materially impacted by these regulatory changes because of the continued use of
the Company's transmission/distribution facilities and the Company's limited
exposure in California. See Item 7, California Matters.
------------------
In preparation for competition, the Company has reduced ongoing costs and
improved operations. Nevada electric and gas rates will remain frozen until
December 31, 1999. A Nevada rate plan is currently in effect that provides for
a 50/50 sharing between customers and shareholders of electric and gas earnings
in excess of a 12 percent return on equity. In addition, in lieu of a 50%
refund, SPPC can apply excess electric earnings to buy down, or buy out of,
higher cost long-term fuel and purchased power contracts.
For more information regarding regulatory changes affecting SPPC, see Item
7, Nevada Matters, California Matters, FERC Matters and Note 2 of the Company's
-------------- ------------------ ------------
consolidated financial statements.
Merger
On April 29, 1998, SPR announced a proposed merger with Nevada Power
Company, of Las Vegas, NV. The "merger of equals" will create a combined
company with assets of approximately $4 billion.
On July 7, 1998, SPR and Nevada Power Company issued a press release
announcing the filing of a joint merger application with the PUCN for approval
of their proposed merger. In the filing, SPR and Nevada Power proposed selling
their generating plants, pending merger completion, and a long-term freeze in
prices for regulated utility services (transmission and distribution). The
application stated that capital raised by the sale of generating plants would be
reinvested primarily in new transmission and distribution facilities. An
incentive mechanism through which net merger savings and other benefits would be
shared by customers and investors was also proposed. Hearings before the Public
Utilities Commission of Nevada (PUCN) were held in November/December 1998 in Las
Vegas and Carson City. (Hearings were completed on December 2, 1998).
Both Sierra Pacific Resources and Nevada Power held special stockholder
meetings in October 1998 during which stockholders of both companies voted to
approve the proposed merger. On December 31, 1998, the PUCN approved the
proposed merger subject to conditions regarding the divestiture of the two
companies generating plants, merger cost savings and filing of unbundling cases
before the PUCN. More specifically, the conditions require that the companies:
file a generation divestiture plan with the PUCN for review and commit to divest
pursuant to the plan; file an interim independent system administrator (ISA)
proposal at FERC and for PUCN review; file a generation tariff at FERC and for
PUCN review; file a general rate case and unbundle costs; after a three year
freeze on retail rates, file a rate case to prove and capture synergies; and
submit an application to the PUCN to recover stranded costs. The companies
filed a formal petition for clarification in January 1999. The petition for
clarification was granted on January 29, 1999, with minor language changes
acceptable to both companies.
The proposed merger is conditioned, among other things, upon further
regulatory approvals including the SEC, Department of Justice, the Federal Trade
Commission and FERC. The application under the Public Utility Holding Company
Act of 1935 was filed with the SEC on February 11, 1999. Hart-Scott-Rodino
filings with the Federal Trade Commission and the Department of Justice were
made on February 17, 1999. The merger application was filed with the FERC on
October 2, 1998, and required responses to interventions have
6
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been completed. If all conditions can be resolved satisfactorily between the
companies and the regulators, the merger is expected to be completed in the
Second Quarter of 1999.
Generation Divestiture
In June 1998, the Company announced the plan to divest its generation
assets. The announcement was included in the merger application filed with the
PUCN on July 7, 1998.
The Company has 1,051 megawatts (net capacity) of fossil fuel and hydro
generation facilities. The fuel mix consists of coal, natural gas and oil.
Current total book value for all generation assets, at year-end 1998 was $379
million.
The Company has retained an advisor to manage the generation sale and
conduct the auction for both SPPC and Nevada Power Company.
The merger order, dated December 31, 1998, requires that a divestiture plan
be filed with the PUCN as a compliance item, prior to closing the merger. This
plan will be filed on or before April 1, 1999. The plan will include details
about the auction process, market power mitigation through sales of assets in
bundles, description of the generation tariff, and a description of the proposed
interim independent system administrator structure for transmission.
A generation auction will be held. At this time, the preliminary schedule
will include issuance of an offering memorandum in or around July 1999. The
offering memorandum will describe the assets, the auction process, and the terms
and conditions for bidding. First round bids will be expected in or around
October 1999. After evaluation of these bids, a short list of qualified bidders
will be selected in the second round. Final bids are expected in or about
January 2000, with expected sale and transfer of assets by August 2000.
ELECTRIC BUSINESS
Business and Competitive Environment
The Company's electric business contributed $586 million (79.8%) of 1998
operating revenues. Typically the electric business may peak in either summer
or winter. The system has an annual load factor of approximately 71.5%, which
is higher than the industry norm.
Winter peak loads are due to shorter daylight hours, colder temperatures
(which affect space heating requirements) and ski resort demands (snowmaking,
hotels, lifts, etc.). Summer peak loads result from air-conditioning, cooling
equipment and irrigation pumping. The Company's peak load increased an average
of 6% annually over the past five years, reaching 1,423 megawatts (MW) on August
5, 1998. The Company's total electric MWH sales have increased an average of
7.5% annually over the past five years.
A significant part of the growth in the Company's electric sales has
resulted from growth in the residential area, mining and manufacturing industry
in northern Nevada.
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SPPC's electric customers by class contributed the following percentages
toward 1998 megawatt-hour sales:
<TABLE>
<CAPTION>
MWH
SALES
<S> <C>
Residential 20.4%
Commercial and Industrial:
Mining 27.1%
Offices/Schools/Government 10.7%
Resorts & Recreation 7.8%
Manufacturing / Warehouse 7.6%
All Other 11.8%
Wholesale 14.6%
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Total 100.0%
=====
</TABLE>
Residential and small commercial sectors increased 4.9%, the highest growth
rate in recent history for those classes.
In response to this growth, SPPC has provided customers with additional
choices in the design and installation of electric service. Under this program,
customers may select a contractor other than the Company to design and install
facilities. Additionally, the Company has worked closely with developers to
redesign the new business process that resulted in improved efficiencies and
increased customer satisfaction. The Company continues to evaluate new
technology such as automated dispatch and mobile data capabilities to enhance
efficiency measures.
Nevada leads the nation in gold production, accounting for approximately
76% of all U.S. production and 11% of world production, ranking it the third
largest gold producer in the world. It is estimated that Nevada gold production
for 1998 was approximately 8.8 million ounces. A majority of Nevada's gold
mines are customers of the Company. Currently, known gold reserves at existing
mines in Nevada total approximately 90 million ounces, over 75% of the nation's
known gold reserves. These reserves are sufficient to continue production at
current rates for the next decade.
During 1998, world gold prices ranged from about $273 per ounce to $315 per
ounce. Production costs vary greatly at Nevada mines, along with profitability.
Mining industry reports indicate many Nevada gold mines have a production cost
of less than $300 per ounce, with some of the larger mines producing within the
$192 to $240 per ounce range. When compared to world production costs, Nevada
is well below the worldwide average of $262 per ounce. While Nevada's gold
mines have the lowest costs in the world, investments in exploration and
development have fallen, and may continue to fall. In addition, the low gold
price may also shorten the expected mine lives of certain Nevada properties as
lower grade ore becomes uneconomic to mine.
The Company's territory also has a variety of other mineral producing
mines. Approximately 22 million ounces of silver were produced in 1998, worth
approximately $122 million, with over 300 million ounces of silver resources
identified in the State. Silver demand has been exceeding new supply for most
of the decade, drawing down inventories built up in the 1980's. As this
situation continues, we will see continued upward pressure on silver prices.
Other minerals produced in Nevada include copper, lithium, mercury, barite,
diatomite, gypsum, and lime, valued at over $400 million.
8
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The Company has nine long-term power sales agreements with major mining
customers with terms of at least five years. The final contract expires in
2005. Five of these agreements have been reviewed and approved by the PUCN as
part of the Company's new tariff structure designed for major customers. These
mining agreements secure over 223 megawatts of present and future mining load,
or approximately $74 million in annual revenues, which is 12.6% of the 1998
electric operating revenues. The agreements require that customers maintain
minimum demand and load factor levels, and include termination charge provisions
to recover all of the Company's customer-specific facilities investment.
The resorts and recreation group is comprised of hotels, casinos, and ski
resorts. This major customer segment comprises 7.8% of the total electric
system retail KWH sales. Tourism and gaming continue to be key contributors to
the local economy. The economic impact, on Washoe County, Reno and environs in
1998 was estimated at over 4.3 billion dollars. Several of the largest gaming
customers are expanding their properties to differentiate the Reno/Tahoe market
by creating a more desirable resort location. These same large gaming customers
increased their 1998 electric load by 8,573 MWH (1.1%) over 1997.
Growth in the Northern Nevada gaming sector in recent years has provided
significant energy sales and revenue growth for the Company. Gaming sector
energy sales growth has averaged 3.8% annually over a recent five year period.
The advent of increased competition, particularly "Indian gaming" in key
feeder markets, and the continuing expansion in Las Vegas, may have a
potentially negative impact on the Northern Nevada market share and ultimately
energy sales. The passing of Proposition 5 in California, which liberalizes
Indian reservation gaming operations, has been predicted to cause a decline in
Reno's gaming revenues once implemented. Northern Nevada casinos are evaluating
and implementing competitive strategies to expand their entertainment portfolio.
The key to this strategy is packaging entertainment value, customer comfort, and
reasonable pricing, with the natural attraction of the Sierra Nevada geographic
location.
The Company's industrial and large commercial customers continue their
interest in the electric supply source options potentially available to them
under regulatory reforms currently being considered in Nevada and in place in
California. The Company continues to prepare for a more competitive environment
and has actively participated in regulatory reform deliberations in Nevada. See
Item 7, Nevada Matters, California Matters, and FERC Matters.
-------------- ------------------ ------------
Over the past five years, MWH sales to wholesale customers have increased
at a rate of 21%. During 1998, firm and non-firm sales to wholesale customers
comprised about 14.6% of total energy sales. The wholesale market is very
competitive and sales into this market are typically made at very low margins.
This market is maturing and will become even more competitive in the future.
<TABLE>
<CAPTION>
Percent
(MWH) of Total
---------- ----------
<S> <C> <C>
Firm Sales 115,856 9.3%
Non-firm Sales 150,319 12.1%
Firm Off-System Sales 974,490 78.6%
---------- ------
Total 1,240,665 100.0%
========== ======
</TABLE>
While the wholesale sales in 1998 represented 14.6% of sales they represent
only 5.7% of electric revenues. Recent changes in Federal regulations covering
the rules under which transmission systems are
9
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operated will increase competition for wholesale sales and may impact the level
of firm and non-firm wholesale sales made in the future. See Item 7, FERC
----
Matters.
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MAJOR PROJECTS SUMMARY
The following projects were approved in previous resource plans. See Rate
----
Proceedings.
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Pinon Pine Power Project
In August 1992, the Company executed a cooperative agreement with the U.S.
Department of Energy (DOE) for the construction of a coal-gasification power
plant. The project, known as the Pinon Pine Power Project (Pinon) was selected
by the DOE for funding under the fourth round of the Federal Clean Coal
Technology Program.
This clean coal integrated gasification combined-cycle power plant is
designed to operate on syngas produced from coal, natural gas, and potentially
other fuels. The project consists of a coal gasification facility (including
solids receipt, handling, preparation and storage), and a Company-owned power
island and post gasification facility to partially cool and clean the syngas
produced by the gasifier. Its capacity rating is 93 megawatts in the winter
and 89 megawatts in the summer.
The DOE has committed $168 million of funding for Pinon construction and
operation costs. The DOE provided funding for approximately 43% of the
estimated construction cost and half of the operating and fuel expenses until
the commitment is expended. A dispute has arisen with the Department of Energy
(DOE) regarding the historical and future funding of natural gas costs. In
February 1999 the DOE informed the Company it will not fund the remaining $14
million under the cooperative agreement until the dispute is resolved.
Estimated construction start-up and commissioning costs for Pinon, including the
DOE's portion are approximately $301.5 million, which includes permitting,
taxes, start-up commissioning, operator training and Allowance for Funds Used
During Construction. DOE funding for construction through December 1998 is
$132.4 million.
The Company's expected cost per kilowatt of capacity net of DOE
construction after commissioning of all coal gasification facilities is $1,574
based on the peak winter rating and $1,739 based on the summer rating.
Construction began on the project in February 1995, following resource
plan approval and the receipt of all permits and other approvals. The natural
gas portion (combined cycle combustion turbine) was satisfactorily completed and
placed in service December 1, 1996. The balance of the plant was placed in
service in June 1998. The construction of the gasifier portion of the project
overran the fixed contract price by approximately 12% or $12.6 million. The
overrun is primarily due to redesign issues, resolving technical issues relative
to start up and other costs due to a later than anticipated in-service date. To
date, the Company has not been successful in obtaining sustained operation of
the gasifier but work continues to identify problem areas and redesign solutions
which will likely require additional capital expenditures. Due to the problems
noted above, the Company and Foster Wheeler settled on a portion of the cost
overrun and have entered into an alternative dispute resolution process in an
attempt to resolve remaining issues on total construction costs. At this time,
the Company does not have any estimates as to the outcome of the proceeding.
Pinon Pine Corp. and Pinon Investment Co., subsidiaries of the Company, own
25% and 75% of a 38% interest in Pinon Pine Company, L.L.C. GPSF-B, a Delaware
corporation formerly owned by General Electric Capital Corporation (GECC) and
now also owned by the Company, owns the remaining 62%. The LLC was
10
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formed to take advantage of federal income tax credits associated with the
alternative fuel (syngas) produced by the coal gasifier available under (S) 29
of the Internal Revenue Code.
The Company is contractually obligated to build and operate the gasifier
for the LLC and to purchase from the LLC the syngas produced in the gasifier for
use in the Company-owned power island. The obligations are contingent on the
gasifier meeting the necessary requirements to be eligible for Section 29
credits. The Company also has contractual performance covenants and warranties
requiring, among other things, that the gasifier operate at 30% capacity in
1997, and that construction of the facility be completed to GECC's satisfaction
before June 30, 1998.
Because the gasifier failed to attain an average capacity factor of 30%
during 1997 and because it was not completed to GECC's satisfaction prior to
June 30, 1998, Sierra was obligated to make a payment to GECC of $2.8 million in
1997 and was obligated to purchase the facility for the amount of capital
invested by GECC plus a return on capital. The purchase was completed in
February 1999 for $30.4 million.
Alturas Intertie
The Company completed construction of the Alturas Intertie transmission
line in December 1998. The Alturas Intertie was built to enhance service to
existing load, to expand service to new customers and to increase significantly
the Company's access to lower cost resources in the Pacific Northwest. This 345
kV line originates west of Alturas, California and extends 165 miles south to
Reno. Construction commenced on February 9, 1998. The line was placed into
commercial operation on December 22, 1998. The Company spent approximately $144
million on the project as of December 31, 1998. The current estimated cost of
construction, including AFUDC, is approximately $159 million. Additional
environmental and right-of-way restoration activities are expected to continue
on the project through 2004.
Certain northern California public power groups have challenged the
Company's filing with FERC of the interconnection and operating agreements
related to the Alturas Intertie in December 1998 and January 1999. The
California groups allege 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. One of the California
groups, the Transmission Agency of Northern California (TANC), has initiated
related 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 Bonneville Power Administration's (BPA) 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.
Each complaint is directed at BPA, which is charged with administering the
Northwest Power Preference Act and has determined that its construction
activities did not violate that act. The Company is in the process of
intervening in these proceedings and opposing TANC's complaint and requested
relief.
TANC's allegations have already been rejected by the Western Systems
Coordinating Council which determined the capacity rating of the Alturas
Intertie. The Company's position, supported by Bonneville Power Administration
and PacifiCorp, is that under 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 issue is still
pending before FERC. Action is expected by the summer of 1999. Even if the
California groups prevailed, use of the Alturas Intertie would not be affected
other than by certain reductions in imports during peak periods.
11
<PAGE>
FACILITIES AND OPERATIONS
Total System
As of December 31, 1998, the Company's electric transmission facilities
consisted of approximately 4,000 overhead pole line miles and 81 substations.
Its distribution facilities consisted of approximately 9,000 overhead pole line
miles, 4,500 underground cable miles and 178 substations.
The Company continues to maintain a wide variety of resources in its
generation system. During 1998 the Company generated 54.4% of its total electric
energy requirements in its own plants, purchasing the remaining 45.6% as shown
below:
<TABLE>
<CAPTION>
Megawatt- Percent
Hours of Total
----------------- --------------
Company Generation
------------------
<S> <C> <C>
Gas/Oil 3,330,179 32.8%
Coal 2,133,351 21.0%
Hydro 60,732 0.6%
--------- ------
Total Generated 5,524,262 54.4%
--------- ------
Purchased Power
--------------------
Long-Term Firm:
Utility Purchases 3,461,474 34.1%
Non-Utility Purchases:
Geothermal 754,204 7.4%
Other 111,957 1.1%
Spot Market 304,716 3.0%
--------- ------
Total Purchased 4,632,351/1/ 45.6%
--------- ------
Total 10,156,613 100.0%
========== ======
</TABLE>
The Company's decision to purchase spot market energy is based on the
economics of purchasing "as-available" energy when it is less expensive than the
Company's own generation. At the time of the 1998 system peak, the Company had
purchased firm capacity under long-term contracts with other utilities and
qualifying facilities (QFs) equal to 26% of total peak hour capacity. In 1998,
most of the Company's non-utility generation came from QFs, except for 12,224
megawatt hours, which came from two small power producers.
- -------------------
/1/ Total purchased megawatt-hours include immaterial inadvertent purchases
which are not included in the purchases in the Management Discussion and
Analysis.
12
<PAGE>
Load and Resources Forecast
The Company has committed as part of the merger agreement with PUCN to
divest its generation facilities to enhance competition in a deregulated
environment. Current plans call for the divestiture to occur in the year 2000.
Until such time, the Company will continue to provide energy through generation
and purchase power to meet both summer and winter peak loads. The Company's
actual total system capability and peak loads for 1998, and as estimated for
summer peak demand through 2000 (assuming no curtailment of supply or load and
normal weather conditions), are indicated below:
<TABLE>
<CAPTION>
Capacity at 1998 Peak Forecast Summer Peak
-------------------------------------------------------------------------------------
MW % 1999 2000
--------------- --------------- --------------- ---------------
<S> <C> <C> <C> <C>
Company Generation:
Existing 1,045 65% 1,045 1,052
--------------- --------------- --------------- ---------------
Purchases:
Long/Short-Term Firm (1) (2) 251 16% 475 491
Interruptible Customers 2 0% 2 2
Non-Utility Generators 70 4% 70 70
--------------- --------------- --------------- ---------------
Subtotal 323 20% 547 563
--------------- --------------- --------------- ---------------
Additional Required 248 15% 11 90
--------------- --------------- ---------------
Total System Capacity 1,616 100% 1,603 1,705
=============== =============== =============== ===============
Net System Peak (3) 1,423 88% 1,407 1,500
Planning Reserve 193 12% 196 205
--------------- --------------- --------------- ---------------
Total 1,616 100% 1,603 1,705
=============== =============== =============== ===============
Growth over previous year -0.8% 5.5%
=============== ===============
</TABLE>
(1) Value net of losses.
(2) Includes potential short-term firm purchases that are not under contract.
Values shown represent purchases within existing transmission system
limits.
(3) The system peak shown for 1998 is the actual system peak of 1,423 MW,
which occurred on August 5, 1998.
With regard to total system capacity, the Company is expected to maintain
a planning reserve margin consistent with the Western System Coordinating
Council guidelines. This reserve margin was 193 megawatts in 1998, which the
Company expects will increase to 205 megawatts by 2000. To accommodate the
system requirement during the 1999-2000 time period, it will be necessary to
secure additional capacity beginning in 1999. The "Additional Required" will be
met by short-term purchases through 2000.
13
<PAGE>
Generation
The Company's total net generating capability for the upcoming 1999 Summer
Peak is as follows:
<TABLE>
<CAPTION>
Number
of MW Year(s)
Name Type/Fuel Units Capacity Installed
- ---- --------- ----- -------- ---------
<S> <C> <C> <C> <C>
Valmy Steam/Coal 2 266 1981 and 1985
Tracy Steam/Gas, Resid. Oil 3 244 1963, 1965, 1974
Pinon Combined Cycle/Coal, Gas 1 89 1996- 1998
Clark Mtn CT's CT/Gas, Diesel Oil 2 138 1994
Ft. Churchill Steam/Gas, Resid. Oil 2 226 1968 and 1971
Other GT/Gas, Diesel Oil, 1899- 1970
Propane, Hydro 33 82
-------
1,045
=======
(CT) Combustion Turbine
(GT) Gas Turbine
</TABLE>
The Company is the operator and owns an undivided 50 percent interest in
the Valmy plant. Idaho Power Company (Idaho Power) owns the remainder. The
capacities shown above for the Valmy plant represent the Company's share only.
The Company owns 100 percent of all of its remaining electric generation plants.
The table above includes the generation capacity of the 100% SPPC-owned power
island portion of the Pinon Pine Power Project. Pinon's current summer net
capacity is 89 MW when operating on natural gas.
Four of the Company's hydro generation units are located on the Truckee
River, which runs approximately 100 miles from Lake Tahoe, through Reno/Sparks,
to Pyramid Lake. A 2 MW facility located on the Truckee River at Farad was
damaged by the January 1997 flood and will not be available for generation
during the 1999 summer peak. The Company had leased two units from the Truckee-
Carson Irrigation District under a 30-year operating lease that expired in 1998
prior to the Company's normal summer peak. The units are located in the
Lahontan Reservoir area, 70 miles southeast of Reno. Negotiations with the TCID
are underway to renew the lease, however, the TCID may keep the two units as a
Qualifying Facility. Due to disrepair of the units, it is not expected that any
generation will be available for the 1999 summer peak. See Leaseholds.
----------
Purchased Power
The Company continues to manage a diverse portfolio of contracted and spot
market supplies, as well as its own generation, to minimize its net average
system operating costs. During 1998, the Company witnessed a dramatic increase
in the price of off system energy, compared to previous years, reflecting the
increase in electricity costs nationwide. Nationally, this increase was due, in
part, to increased demand resulting from above average summer temperatures.
Regionally, below average precipitation in the Northwest aggravated the problem.
The Company is a member of the Northwest Power Pool and Western Systems
Power Pool. These pools have provided the Company further access to spot market
power in the Pacific Northwest and the Southwest. In turn, the Company's
generation facilities provide a backup source for other pool members who rely
heavily on hydroelectric systems. The Company has an agreement with PacifiCorp's
Utah division and Idaho Power in
14
<PAGE>
which a portion of the energy purchased by the Company from PacifiCorp is
transmitted through the Idaho Power system. The agreement also provides added
access to spot market power.
The Company purchases hydro and thermally-produced spot market energy,
by the hour, based upon economics and system import limits. Also purchased,
during peak load periods, is firm block energy as required to maintain adequate
operating reserve margins. During drought years, when less spot market hydro
energy is available, the Company supplies a higher percentage of its native load
utilizing its fossil fuel generation. Of continuing concern to any purchaser of
hydro-generated energy are proposals by federal regulators, in the interest of
the salmon, recommending closure of some hydro operations on the Snake and
Columbia rivers. The amounts of hydro energy available and the price will
depend on weather conditions in the Pacific Northwest and proposals by
regulators. The amount of excess generating capacity in other systems and the
existence of competition in providing utilities with economic incentives to make
off system sales are also important factors.
Currently, the Company has contracted for a total of 265 megawatts of
long-term firm purchased power from the utility suppliers listed below. Several
of the Company's firm purchase power contracts contain minimum purchase
obligations. Meeting these minimums has not been a problem for the Company in
the past, and is not expected to be a problem in the future.
<TABLE>
<CAPTION>
Contract Operation Termination Minimum
Contract Party Capacity Date Date Capacity %
- ------------------------------- ------------------ ------------------ --------------------- ------------
<S> <C> <C> <C> <C>
Idaho Power(1) 75 MW Nov 1989 May 31, 1999 50%
Idaho Power (for Elko) 15 MW Mar 1994 May 31, 2000 40%
Tri-State(2) 25 MW June 1991 June 1, 1999 50%
PacifiCorp 75 MW June 1989 Feb 28, 2009 70%
PacifiCorp/Utah Power(3) 75 MW May 1991 April 30, 2000 78%
</TABLE>
(1) The Company will not renew this contract.
(2) The Company has provided notice to terminate the Tri-State contract
effective May 31, 1999.
(3) The Company has provided notice to terminate the PacifiCorp/Utah contract
effective April 30, 2000.
According to regulations of the Public Utility Regulatory Policies Act, the
Company 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, 1998, the Company had a total of 109
megawatts of maximum contractual firm capacity under 15 contracts with QFs. The
Company also had contracts with three projects at fluctuating short-term avoided
cost rates. All QF contracts currently delivering power to the Company at long-
term rates have been approved by either the PUCN or the CPUC, and have QF status
as approved by FERC. One long-term QF contract terminates in 2006, one
terminates in 2039, and the remainder terminate between 2014 and 2022.
Energy purchased by the Company from QFs constituted 10% of the net system
requirements during 1998. These contracts continue to provide useful diversity
for the Company in meeting its peak load. All the QFs from which the Company
makes firm purchases are either geothermal (87%), hydroelectric or biomass.
The actual QF firm capacity output under contract was 64 megawatts during
the summer of 1998. The actual QF output for all non-utility generator
deliveries during the summer 1998 peak was 83 megawatts. The table on page 12
reflects actual performance during the 1998 summer peak period. A difference
exists between the non-utility generator figures and the table on page 12
because the 1998 figure is actual and the remaining
15
<PAGE>
years are forecasts. Any capacity shortfall created by under-performance was
included in the Company's 1998 amended resource plan.
Transmission
In planning its transmission capacity, the Company considers generation and
purchased power options, as well as the requirements for providing retail and
wholesale transmission services.
The Company'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, and 250 miles from the Reno area south to Tonopah,
Nevada. A 230 KV transmission line connects the Company to facilities near the
Utah-Nevada state line, which in turn interconnects the Company to Idaho Power
facilities at the Idaho-Nevada state line. The Company also has two 120 KV lines
and one 60 KV line which interconnect with Pacific Gas and Electric (PG&E) on
the west side of the Company's system at Donner Summit, California. Two 60 KV
transmission ties allow wheeling of up to 14 megawatts of power from the Beowawe
Geothermal Project, which is located within the Company's service area, to
Southern California Edison. These two minor interties are available for use
during emergency conditions affecting either party.
The Company's transmission intertie system provides access to regional
energy sources.
Completion of the Alturas Intertie in 1998 provides the means of serving
existing native load and new customers, and significantly increases the
Company's capacity to import more firm capacity and energy from other regions.
See Alturas Intertie discussion, page 11.
Fuel Availability
The Company's 1998 fuel requirements for electric generation were provided
by natural gas (60.7%), coal (39.0%) and oil (0.3%). During 1998 natural gas
remained the fuel of choice, over oil, for generation plants other than Valmy,
which is a coal-fired plant.
The average costs of coal, gas and oil for energy generation per million
British thermal units (MMBtu) for the years 1994-1998 were as follows:
<TABLE>
<CAPTION>
Average Consumption Cost ($/MMBtu)
1994 1995 1996 1997 1998
------------ -------------- -------------- --------------- ---------------
<S> <C> <C> <C> <C> <C>
Gas $2.19 $1.65 $2.10 $2.03 $2.12
Coal 2.07 2.19 1.88 1.80 1.56
Oil 3.37 3.80 3.48 3.35 3.96
</TABLE>
Since beginning commercial operation of its Valmy coal-fired generating
units in the early 1980s, the Company operated these units at a higher load
level than its gas/oil-fired units because gas and oil fuels had generally been
more expensive. However, beginning in 1989, the Company operated its gas/oil-
fired units at increased levels due to competitive pricing of natural gas. In
September 1996, the Company began purchasing coal on the spot market at prices
more competitive than gas, oil and long-term contract coal. As a result, except
during periods of low-cost surplus hydro energy availability, load levels on the
Valmy units have been consistently high since that time.
16
<PAGE>
The Company's long-term contract with Black Butte Coal Company (Black
Butte) 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 canceled. Due to previous accelerated
purchases and cancellations and continuing cancellations of minimum monthly
volume obligations (described below), the Company projects it will fully satisfy
all volume requirements and that termination of the contract will occur sometime
in early to mid-2002. At that time, absent divestiture, the Company will pursue
lower fuel cost alternatives, which may include additional purchases of spot
market coal should pricing remain favorable.
Beginning in June 1996, the Company, along with its joint-ownership partner
(Idaho Power Company), implemented an economic cancellation strategy which
essentially buys down minimum tonnage requirements under the Black Butte
contract rather than taking physical delivery of the coal. Canceling the Black
Butte tonnage creates various economic and operating benefits, primarily
opportunity to buy lower-cost spot market coal and reduce overall fuel costs.
In June 1996, the Company and Idaho Power expended $5 million ($2.5 million
each) to cancel all minimum volume requirements for the 1996-97 contract year.
The Company agreed with Idaho Power to satisfy even more volume requirements in
the fall of 1996 and in June 1997 by matching the dollar cost of Black Butte
tonnage purchased by Idaho Power for delivery to Idaho's coal-fired Jim Bridger
plant. The Company expended $3.8 million for these matching cancellations.
Since July 1997, the Company and Idaho Power have canceled (or delivered to the
Bridger plant) minimum Black Butte volume requirements on a monthly basis.
During the third quarter 1998, minimum contract quantities were delivered to
Idaho Power's Bridger plant, with these deliveries credited to Valmy
requirements under the Black Butte contract.
The Company'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 which the Company 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 Fuel properties, including SUFCO) on June 1,
1998.
During 1998, several short-term agreements for the purchase of spot market
coal were executed. The source of this coal is the Uinta Basin of Utah. These
spot market purchases supplement base volume requirements under the Company's
long-term coal contracts at a cost approximately one-half that of contract coal.
The total amount of coal burned at the Valmy Power Plant during 1998 was
1.6 million tons. As of December 31, 1998, the coal inventory level was 272,332
tons, or approximately 47.6 days of consumption at 100% capacity. The Company
targets an average annual coal stockpile sufficient to provide 30 days supply at
full load.
Valmy had coal delivered under a June 30, 1986 contract with the Union
Pacific Railroad Company (UP). This contract expired on July 31, 1997 and the
parties were unable to reach an agreement on a new contract. Subsequently, the
UP filed a common carrier rate under which these coal deliveries moved while
negotiations were ongoing.
On August 1, 1997, the Company and Idaho Power filed a complaint with the
Surface Transportation Board (STB) alleging that rates assessed by UP to move
coal from Sharp, Utah to Valmy exceeded a maximum reasonable level and that UP
possesses market dominance over that traffic. The Company and Idaho Power
requested that the STB prescribe maximum reasonable rates, along with related
rules and service terms for this movement. UP counterclaimed that no such market
dominance exists and consequently, the STB did not have jurisdiction.
17
<PAGE>
While this case proceeded, the Company and Idaho Power continued to
negotiate a solution to the dispute. Although the Company and Idaho Power were
unable to negotiate rates with the UP which were believed to be reasonable based
on the railroad's variable cost of transportation, the rates finally obtained
were very similar to those in the previous agreement and will allow the
utilities to continue shipping contract coal, as well as spot market coal, to
the Valmy power plant. Two new 3-year transportation agreements (one UP direct
haul and one UP/Utah Railway joint haul) were executed with the UP, with an
effective date of June 1, 1998.
During 1998, the Company operated the Pinon Pine facility almost
exclusively on natural gas. Although no coal was purchased in 1998 for synthetic
gas production in the plant's coal gasification facility, approximately 19,000
tons were purchased in 1997. This inventory has been more than sufficient to
fuel the gasifier during its limited operation in 1998. Total coal burned in the
gasifier during 1998 was 488.5 tons, with another 500 tons being sold to a local
manufacturer. Petroleum coke (used for gasifier startup) purchased in 1998 was
404 tons, with 913 tons being burned. The Company expects to purchase additional
coal tonnage on a spot market basis from Arch Coal's SUFCO mine to meet any coal
gasification requirements.
The Company meets its needs for residual oil for generation through
purchases on the spot market. With no other mitigating factors, the Company's
residual oil inventory policy is to maintain 50,000 to 75,000 barrels at each of
its Tracy and Ft. Churchill generating plants. Based on Year 2000 contingency
plans, the Company is contemplating the possibility of increasing storage to
full capacity prior to 1/1/2000, which would provide up to 17 days' supply at
full load operation. The actual residual oil inventory level at these two sites
was 114,960 barrels as of December 31, 1998, which is equal to 4.3 days' supply
at full load operation. Total residual oil consumption in 1998 was 64,106
barrels. Approximately 83 percent of this consumption occurred in the month of
December, with extremely cold temperatures resulting in gas supplies being
restricted for retail customer demand.
NATURAL GAS BUSINESS
BUSINESS AND COMPETITIVE ENVIRONMENT
The Company's natural gas business is a local distribution company (LDC) in
the Reno/Sparks area that accounted for $99.5 million in 1998 operating
revenues, or 13.6% of total Company operating revenues. Growth in the Company's
service territory continues to be strong. Residential customer growth during
1998 was 4.4%. Residential sales growth has been boosted by an increase in
multi-family housing construction activity and an aggressive residential
marketing campaign targeting existing propane and fuel oil conversions. The
overall natural gas customer growth rate was 4.0% for the year.
Natural gas offers significant economic and environmental advantages over
other energy sources for space heating, water heating and other uses in
residential, commercial and industrial applications. Growth in the residential
and small commercial sector is expected to continue as new developments in the
Company's distribution service area are planned. A new record peak day sendout
of 125,457 decatherms was reached on December 22, 1998.
Competitive Issues
Contracts established during the last three years under the Company's Value
Based Service Tariff (VBST) are being successfully renewed as the old contracts
expire. During 1998, four contracts were renewed and one new contract was
signed under the VBST tariff designed to enable the Company to compete with
18
<PAGE>
competitive service options for its largest customers. At December 31, 1998, the
Company had ten VBST contracts in place with customers.
The Company'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. Four customers now secure their own
gas supplies, with the Company providing transportation service on its
distribution system.
FACILITIES AND OPERATIONS
The Company has contracted for firm winter-only and annual gas supplies
with 12 Canadian and domestic suppliers to meet the firm requirements of its LDC
and electric operations. The contracts total 157,000 decatherms per day through
February 1999; 152,000 decatherms per day for March 1999; 93,000 decatherms per
day through April 1999; 78,000 decatherms per day for May through October 1999
and 65,000 decatherms per day for the remainder of the year. Most of these
contracts provide for a fixed price. This ensures that the Company is able to
lock in a significant portion of its gas supply cost while retaining the
flexibility to purchase spot market supplies.
The Company'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 a liquified 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
decatherms per day of peaking supplies. The Company meets its peak day
requirements above Northwest/Paiute capacity with firm transportation capacity
on the Tuscarora pipeline and Pacific Gas Transmission Company (PGT) pipeline.
Starting November 1, 1996, the Company 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 the Company 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. The
Company 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 the Company's current gas supply program. 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
the Company's electric generating plants. Storage capacity is generally used
for the peaking requirements of the LDC.
19
<PAGE>
Transportation Capacity
<TABLE>
<S> <C> <C> <C>
Northwest - 68,696 decatherms per day firm
90,000 decatherms per day interruptible
Paiute - 103,774 decatherms per day firm from November through March
61,044 decatherms per day firm from April through October
90,000 decatherms per day interruptible
NOVA - 30,000 decatherms per day firm
ANG - 30,000 decatherms per day firm
PGT - 30,000 decatherms per day firm
40,270 decatherms per day firm (winter only)
90,000 decatherms per day interruptible
Tuscarora - 104,000 decatherms per day firm
60,000 decatherms per day interruptible
</TABLE>
Storage Capacity
<TABLE>
<S> <C> <C> <C>
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
</TABLE>
Total LDC decatherm supply requirements in 1998 and 1997 were 14.9 million
decatherms and 12.4 million decatherms, respectively. Electric generating fuel
requirements for 1998 and 1997 were 35 million decatherms and 32 million
decatherms, respectively.
As of December 31, 1998, the Company owned and operated 1,296 miles of
three-inch equivalent natural gas distribution lines.
WATER BUSINESS
The water distribution business contributed $49.1 million (6.6%) to the
Company's 1998 operating revenues.
The PUCN issued an order in April of 1998 on the application filed in 1997,
requesting authorization to increase general water rates for all classes of
customers to recover approximately $119 million in net plant additions to the
water facilities due to the passage of the Safe Drinking Water Act in 1986 and
increased capacity. The final order resulted in an overall increase of $4.3
million in general rates. This equates to a 9.4% increase to the average
customer.
Water production in 1998 totaled 22.1 billion gallons. 2.5 billion gallons
were produced from the Company's groundwater wells. The remaining 19.6 billion
gallons were treated through the Company's two water treatment facilities; the
Chalk Bluff Water Treatment Plant and the Glendale Water Treatment Plant. The
Company's peak day send-out of water during 1998 was 130.9 million gallons, a
7.9% increase over the 124 million gallon peak set in 1997. The sizable peak day
increase was due to abnormally warm weather with temperatures in excess of 100
degrees for more than a week. Overall weather conditions during the year
produced an average snow pack with a cool late spring, thus annual production
was down 5.1%.
The Company's water supplies are from both surface and groundwater sources,
with the addition of drought storage and refill provisions sufficient to
withstand prolonged drought conditions. The surface water
20
<PAGE>
source is the Truckee River, which originates in Lake Tahoe and flows north and
east through the cities of Reno and Sparks to Pyramid Lake, located northeast of
Reno.
The Company's groundwater comes from 24 supply wells located around
the Reno/Sparks area. Man-made contaminants, perchloroethylene, from local
business operations have been found at levels exceeding the drinking water
standards in five of these wells. All five of these wells have now been fit
with treatment equipment which allows them to be returned to operation and
deliver water to the system which meets federal standards. The newly formed
Washoe County remediation district sent out the first bills to collect funds to
reimburse the Company for the cleanup of this groundwater contaminant in these
five wells. One of these five wells is currently out of service due to a fuel
leak at a near by gas station and the impending threat of MTBE or petroleum
contamination. The Company has been putting pressure on the regulatory agencies
and the perpetrator to put the appropriate barriers in place so that this well
may be pumped for remediation purposes.
Additionally, the Company has four wells which currently exceed the
federal drinking water standard for naturally occurring arsenic concentrations.
Production from three of these wells continues by blending water treated at the
Glendale Water Treatment Plant. The fourth well is out of service pending
treatment. The Company's water laboratory research staff are developing options
to assure that the Company is prepared to meet new arsenic standards.
A favorable decision rendered by the state engineer allowing the
transfer of agricultural water rights to municipal use for new development in
the Truckee Meadows has been appealed by Churchill County and the City of Fallon
in District Court. The Company continues to provide a temporary back up of the
protested water rights by pledging the Company's certificated rights to back up
the protested transfers so the state engineer will continue to sign subdivision
maps. This process has enabled water service commitments to continue until
protests can be cleared.
The Company continues to pursue the Negotiated Settlement which has
been under development for several years. The Company is currently operating
under a Preliminary Settlement Agreement (PSA) and interim storage contract
until negotiations are completed and the final Truckee River Operating Agreement
(TROA) is completed. A draft environmental impact statement (EIS) and contract
was issued in early 1998 for review and comments and a final EIS will be
prepared subsequent to the completion of the TROA. The Negotiated Settlement is
a complex set of agreements on Truckee River issues involving the United States,
California and Nevada governments, the Pyramid Lake Paiute Tribe and the
Company. It is expected the agreement will be finalized this year. During 1998,
these negotiations progressed with the resolution of many issues toward the
completion of the draft TROA. Once in effect, the new agreement will allow the
Company use of federal reservoirs for drought reserve storage.
The Company plans to rebuild the Farad dam and put the Farad Hydro
plant back into service in 2000. The dam was destroyed during the New Year's
flood of 1997. The water rights associated with the hydro facilities and part
of the Negotiated Settlement provide for river flows to the water division and
therefore, the four Truckee River hydro plants will stay with the water business
even after generation divestiture. See Merger/Generation Divestiture discussion
at page 6.
As a condition of the Negotiated Settlement, the Company's unmetered
residential water customers must be converted to metered service. A meter
retrofit program was approved by the PUCN and began in 1995. Funding for the
program is provided by new business development and administered by the Company.
The program has installed 4,897 meters (12% of 1995 unmetered customers) and
8,301 boxes without meters (35% of 1995 customers without facilities for meter
installation) since the program's inception. Meter boxes without
21
<PAGE>
meters are installed when roads and sidewalks are replaced. When a meter is
installed, installation costs are significantly lower if the box is already in
place. During 1998, 1,125 meters and 3,099 boxes were installed with contributed
funds. At this time, only customers who volunteer for the program may have
meters installed. Water meters have been required in all new construction since
1986.
The Company has entered into several wholesale water agreements to
treat and supply Truckee River water to developments served by Washoe County.
In addition, the Company has entered into an agreement to purchase the Silver
Lake Water Company pending approval by the PUCN. The Company plans to begin
operation of the two Silver Lake wells and metering, billing, and customer
services in October 1999 assuming PUCN approval is received.
CONSTRUCTION PROGRAM
Construction expenditures, including allowance for funds used during
construction (AFUDC), for 1998 were $183.4 million (including contributions in
aid of construction) and for the period 1994 through 1998 were $804.0 million.
Estimated construction expenditures for 1999 and the period 2000-2003 are as
follows (dollars in thousands):
<TABLE>
<CAPTION>
Total
1999 2000-2003 5-Year
---- --------- ------
<S> <C> <C> <C>
Electric Facilities $ 87,856 $ 414,101 $ 501,957
Water Facilities 20,795 117,448 138,243
Gas Facilities 11,032 40,920 51,952
Common Facilities 5,383 15,208 20,591
--------------------------------------------------------
Total Construction Expenditures $125,066 $ 587,677 $ 712,743
========================================================
AFUDC ($1,995) ($19,616) ($21,611)
Net Salvage, including cost of removal (120) (400) (520)
Net Customer Advances and
Contributions in Aid of Construction (10,242) (40,620) (50,862)
--------------------------------------------------------
Total Cash Requirements $112,709 $ 527,041 $ 639,750
========================================================
</TABLE>
22
<PAGE>
Total construction expenditures estimated for 1999 and the 2000-2003
period, for each segment of the Company's business, consist of the following
(dollars in thousands):
<TABLE>
<CAPTION>
Total
1999 2000-2003 5-Year
---- --------- ------
<S> <C> <C> <C>
Electric Facilities
Distribution $49,802 $ 205,546 $255,348
Generation 9,010 - 9,010
Transmission 20,889 191,465 212,354
Other 8,155 17,090 25,245
----------------------------------------------------------
$87,856 $ 414,101 $501,957
==========================================================
Water Facilities
Treatment and Supply $ 5,302 $ 44,140 $ 49,442
Distribution 15,161 72,029 87,190
Other 332 1,279 1,611
----------------------------------------------------------
$20,795 $ 117,448 $138,243
==========================================================
Gas Facilities
Distribution $10,068 $ 35,913 $ 45,981
Other 964 5,007 5,971
----------------------------------------------------------
$11,032 $ 40,920 $ 51,952
==========================================================
</TABLE>
GENERAL REGULATION
The Company is subject to the jurisdiction of the PUCN and the CPUC
with respect to rates, standards of service, siting of and necessity for
generation and certain transmission facilities, accounting, issuance of
securities and other matters with respect to electric operations. The PUCN also
has jurisdiction with respect to the Company's gas and water operations. The
Company submits integrated resource plans regarding its electric, gas, and water
business operations to the PUCN for approval. /2/
Under federal law, the Company is 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 Company's sales of electricity for resale and the
transmission of energy for others. The FERC also has jurisdiction over the
natural gas pipeline companies from which the Company takes service.
As a result of regulation, many of the fundamental business decisions
of the Company, as well as the rate of return it is permitted to earn on its
utility assets, are subject to the approval of governmental agencies.
The Company is also subject to regulation by environmental
authorities. See Environment.
-----------
RATE PROCEEDINGS
During 1998, 87% of the Company's revenues were from retail sales of
electricity, natural gas and water in Nevada; 5% from retail sales of
electricity in California and 8% from sales of electricity and gas for resale.
- ----------------------
/2/ It should be noted that under Assembly Bill 366 it has been proposed that
the PUCN begin developing resource planning for electric requirements within the
State of Nevada after December 31, 1999.
23
<PAGE>
Nevada Matters
Effective April 29, 1998, the PUCN approved a $4.3 million annual (or
9.4%), water rate increase.
On July 1, 1998, the Company filed its electric resource plan with the
PUCN. The plan discussed generation and transmission alternatives that would
supply Northern Nevada with electricity for the period 1998 through 2017. On
October 6, 1998, hearings on the transmission system impact study were held.
The stipulation reached at the hearings required the Company to re-file its
resource plan at a later date, with an updated load forecast and more detailed
analysis. The plan was re-filed on December 15, 1998 and hearings will be held
in early 1999.
See Item 7, Nevada Matters for a discussion of Nevada restructuring.
------
California Matters
On January 1, 1998, as a result of the CPUC's December 16, 1997
Transition Plan order, the Company implemented a 10%, or a $2.9 million annual,
rate reduction for its residential and small commercial customers using less
than 20 kw of demand monthly. To mitigate the economic effects, the Company is
issuing rate reduction bonds pursuant to securitization authority of the CPUC.
See Item 7, Nevada Matters, California Matters, and FERC matters and
-------------- ------------------- ------------
Note 2 of the Consolidated Financial Statements.
ENVIRONMENT
General
As with other utilities, the Company is subject to federal, state, and
local regulations governing air and water quality, hazardous and solid waste,
land use, and other environmental considerations. These considerations affect
the construction and operation of electric, gas, and water utility facilities.
Nevada's Utility Environmental Protection Act requires approval of the
PUCN prior to the construction of major utility generation and transmission
facilities. The United States Environmental Protection Agency (EPA) and
Nevada's Division of Environmental Protection (NDEP) administer regulations
involving air quality; water pollution; and solid, hazardous, and toxic waste.
The Company's board of directors has a comprehensive environmental
policy and a separate board committee on environmental compliance which oversees
corporate performance and achievements related to the environment. The
Company's corporate environmental policy emphasizes environmental stewardship.
1998 Activities
The Company conducted compliance audits on 38 sites. No additional
remediation is required as a result of these audits.
In 1995, the Company identified one site formerly used for
manufacturing gas from oil. This site was sold in 1997 with full disclosure to
the buyer. Shortly after the sale, the buyer notified the Company of its intent
to file legal action. To date, no such action has been taken. In July, 1998,
the Company entered into an
24
<PAGE>
agreement with the buyer to mitigate the contamination on site to an acceptable
level. Remediation is scheduled to be completed during the second quarter of
1999. Presently, the total cost for this site is estimated to be $850,000, of
which approximately $100,000 has been spent through December 31, 1998. The
remaining balance has been accrued as a liability.
In September 1994, the Company was notified by Region VII of EPA that
the Company 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 the Company voluntarily pay an undefined (pro rata) share
of the ultimate clean-up costs at the Sites. A number of the largest PRPs formed
a steering committee which is chaired by the Company. 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 has retained a
consultant to prepare an analysis regarding the Sites.
The Company has recorded a preliminary liability for the Sites of
$650,000, of which approximately $120,000 has been spent through December 31,
1998. Once evaluations are completed, the Company will be in a better position
to estimate and record the ultimate liabilities for the Sites.
The Company continued and initiated several actions in accordance with
its policy to be an environmental leader in principle and practice. These
actions have:
Resulted in reduced pollutant and greenhouse gas emission rates at power
plants;
Demonstrated stewardship of wildlife and waterfowl habitat on and adjacent to
Company property;
Improved water quality conditions; and
Lowered the cost of compliance with environmental regulations.
During 1998, the Company was awarded bonus sulfur dioxide emission
allowances by the EPA for its use of geothermal energy, a renewable resource.
Under the Acid Rain Rule of the Clean Air Act, bonus emission allowances are
generated to utilities that have avoided sulfur dioxide emissions by using
renewable energy to generate electricity. In 1998, the Company received 623
bonus allowances.
GENERAL FACILITIES
Leases
The Company continues to sublease available space in Sierra Plaza, its
general office complex, to outside companies and other organizations. The
largest lease, which is with Microsoft Licensing, Inc. runs until 2002. Also a
local law firm has signed a lease providing for occupancy starting in the Fall
of 1999.
GENERAL - LEASEHOLDS
During the year, the Company operated portions of its electric system
as lessee under a lease agreement with Truckee-Carson Irrigation District
(TCID). The Company also operates a lease agreement with the Mineral County
Power System.
Under terms of the TCID lease, the Company was obligated to pay an
annual lease payment of $108,000 plus 2% of gross revenues derived from
operations within the leasehold area. This area covers portions of
25
<PAGE>
Washoe (excluding Reno/Sparks), Lyon, Storey and Churchill counties in Nevada.
In 1998, the Company paid approximately $410,000 as 2% of gross revenues
representing royalties through July 1998 when the lease expired.
The lease, which expired in July 1998, obligated TCID to purchase all
Company capital improvements unless the lease was renewed. The Company and TCID
are currently negotiating a new lease. To date, capital improvements, net of
depreciation, total $22.8 million.
Under terms of the Mineral County Power Systems lease, the Company is
obligated to pay, on a sliding scale, a percentage of gross revenues derived
from operations within the leasehold area. The leasehold area includes the
towns of Hawthorne, Mina, and Luning, along with other unincorporated towns
roughly 100 miles southeast of Reno. During 1998, the Company paid $131,000 on
gross revenues of $5.5 million. The lease expires in 2000. As with TCID,
Mineral County Power System is obligated to purchase any Company capital
improvements unless the lease in renewed. To date, capital improvements, net of
depreciation, total $7.0 million.
GENERAL - FRANCHISES
The Company has nonexclusive franchises or revocable permits, in fact by
grant (in most cases for specified terms of years) or in effect by acquiescence,
to carry on its business in the localities in which its respective operations
are conducted in Nevada and California. The franchise requirements of the
various cities and counties in which the Company operates provide for payments
based on gross revenues. During 1998, the Company collected $8.2 million in
franchise fees based on gross revenues. It also paid and recorded as expense
$1.0 million of fees based on net profits.
<TABLE>
<CAPTION>
Franchise Type of Service Expiration Date
- ------------------------------------ ---------------------------------- -------------------------------
<S> <C> <C> <C>
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 LakeTahoe Electric April 2018
Washoe County Gas and Water May 2015
Washoe County Electric September 2015
Eureka County Electric July 2018
</TABLE>
The Company applies for renewal of franchises in a timely manner prior
to their respective expiration dates.
GENERAL RESEARCH AND DEVELOPMENT
SPPC participates in several utility associations, including the
Electric Power Research Institute and Gas Research Institute.
ITEM 2. PROPERTIES
The general character of SPPC's principle facilities is discussed in
Item 1,
Business.
- --------
26
<PAGE>
Substantially all utility plant is subject to the lien of the Indenture of
Mortgage, dated December 1, 1940, and supplemental indentures thereto between
the Company and State Street Bank and Trust, as trustee, securing the Company's
outstanding first mortgage bonds.
ITEM 3. LEGAL PROCEEDINGS
SPPC, through the course of its normal business operations, is currently
involved in a number of 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
27
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The Company is a wholly-owned subsidiary of Sierra Pacific Resources and, as
such, its common stock is not publicly traded and no market exists for it. Cash
dividends declared on common stock were as follows (dollars in thousands):
<TABLE>
<CAPTION>
1998 1997
------- -------
<S> <C> <C>
First Quarter $19,000 $18,000
Second Quarter 19,000 18,000
Third Quarter 19,000 18,000
Fourth Quarter 19,000 18,000
------- -------
Total 1998 $76,000 $72,000
======= =======
</TABLE>
Note: The dividends scheduled above represent payments from the Company to
its parent, Sierra Pacific Resources. Dividends declared by SPR on its publicly
traded stock totaled $40.3 million during 1998.
After provision for payment of dividends on all outstanding shares of
preferred stock and subject to limitations in the Company's restated articles of
incorporation and its indentures, dividends may be paid on the common stock out
of any funds legally available for that purpose when declared by the board of
directors. As of December 31, 1998, approximately $84.0 million of retained
earnings were available for the payment of dividends on common stock under the
most restrictive of these limitations.
28
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended December 31,
(dollars in thousands)
----------------------------------------------------------
1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C>
Operating Revenues $ 734,332 $ 657,540 $ 619,724 $ 597,784 $ 603,193
========== ========== ========== ========== ==========
Operating Income $ 126,194 $ 120,172 $ 107,008 $ 101,811 $ 95,983
========== ========== ========== ========== ==========
Income Before
Preferred Dividends $ 86,020 $ 83,127 $ 73,651 $ 65,983 $ 60,863
========== ========== ========== ========== ==========
Income Applicable
To Common Stock $ 80,561 $ 77,668 $ 67,351 $ 58,609 $ 52,929
========== ========== ========== ========== ==========
Total Assets $2,011,820 $1,912,242 $1,842,628 $1,729,818 $1,605,710
========== ========== ========== ========== ==========
Long-Term Debt and
Redeemable
Preferred Stock $ 654,950 $ 655,389 $ 655,787 $ 547,124 $ 531,233
========== ========== ========== ========== ==========
Cash Dividends Paid
On Common Stock $ 75,000 $ 70,000 $ 63,000 $ 54,000 $ 51,000
========== ========== ========== ========== ==========
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSIN AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
Net income before preferred dividends in 1998 was $86.0 million, an
increase of $2.9 million over 1997. The Company was authorized to earn a return
on equity of 12% in its Nevada electric operations and 12% and 11.25%,
respectively, in its Nevada gas and water operations. The Company earned in
excess of its allowed regulated returns for its electric and gas operations and
therefore, under its currently effective rate settlement, the Company
anticipates it will make refunds to customers reflecting one half of the excess
earnings. Appropriate reserves have been recorded to reflect the anticipated
refunds. California operations were authorized to earn a return on common
equity of 11.6% in 1998. See Regulatory Matters for more discussion of these
issues.
Nevada, the Company's primary jurisdiction, uses a marginal cost method for
setting electric and gas rates by customer class. As a result, changes in sales
mix can result in variations in revenues, regardless of changes in total
consumption.
29
<PAGE>
The components of gross margin are set forth (dollars in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
Operating Revenues:
Electric $ 585,657 $ 540,346 $ 507,004
Gas 99,532 70,675 67,376
Water 49,143 46,519 45,344
--------- --------- ---------
Total Revenues 734,332 657,540 619,724
--------- --------- ---------
Energy Costs:
Electric 271,773 231,473 223,177
Gas 65,430 38,135 33,859
--------- --------- ---------
Total Energy Costs 337,203 269,608 257,036
--------- --------- ---------
Gross Margin $ 397,129 $ 387,932 $ 362,688
========= ========= =========
Gross Margin by Segment:
Electric $ 313,884 $ 308,873 $ 283,827
Gas 34,102 32,540 33,517
Water 49,143 46,519 45,344
--------- --------- ---------
Total $ 397,129 $ 387,932 $ 362,688
========= ========= =========
</TABLE>
The causes for significant changes in specific lines comprising the results
of operations for the years ended are provided (dollars in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
---------------------------- ------------------------------- ---------------
Change from Change from
Amount Prior year Amount Prior year Amount
----------- ------------- ----------- ------------- -----------
<S> <C> <C> <C> <C> <C>
Electric Operating Revenues:
Residential $ 169,109 3.7% $ 163,003 0.9% $ 161,543
Commercial 178,752 1.9% 175,386 1.2% 173,222
Industrial 184,820 4.7% 176,463 13.9% 154,954
----------- ---------- ----------- -------- -----------
Retail revenues 532,681 3.5% 514,852 5.1% 489,719
Other 52,976 107.8% 25,494 47.5% 17,285
----------- ---------- ----------- -------- -----------
Total Revenues $ 585,657 8.4% $ 540,346 6.6% $ 507,004
=========== ========== =========== ======== ===========
Total retail sales
megawatt-hours (MWH) 8,047,650 3.9% 7,743,799 8.1% 7,161,507
----------- ---------- ----------- -------- -----------
Average retail revenue per MWH $ 66.19 -0.4% $ 66.49 -2.8% $ 68.38
</TABLE>
In 1998, residential and commercial revenues increased due to 2% and 3%
increases in customers, respectively. Industrial revenues were higher in 1998
because of higher use per customer, primarily in the mining industry where
several of the Company's customers expanded operations during 1998. The
increases in revenues for residential, commercial and industrial were all
partially offset by a rate reduction that went into effect March 1997. The
increase in other revenues primarily resulted from higher wholesale electric
sales and a smaller charge for customer refunds. Higher wholesale sales in
1998, $33.1 million compared to $13.3 in 1997, reflect an increased focus on
this business opportunity. The 1998 provision for customer refunds was $4.4
million compared to $7.3 million in 1997.
30
<PAGE>
Residential and commercial revenues increased slightly in 1997 as a result
of a 3% increase in customers. The increase in revenues was partially offset by
a rate reduction that went into effect March 1997. Industrial revenues
increased because of higher use per customer (primarily in the mining segment).
The increase in industrial revenues was also offset by the March 1997 rate
reduction. Other revenues were higher in 1997 primarily due to a customer
refund charge of $7.3 million compared to $12.7 million in 1996.
<TABLE>
<CAPTION>
1998 1997 1996
------------------------------ ------------------------------ ------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------ ------------- ------------- ------------- ------------
<S> <C> <C> <C> <C> <C>
Gas Operating Revenues:
Residential $ 43,833 14.1% $ 38,410 8.5% $ 35,400
Commercial 22,022 12.3% 19,606 6.0% 18,499
Industrial 12,368 6.8% 11,580 6.0% 10,923
Miscellaneous (720) -6.2% (678) -177.9% 870
------------ ----------- ------------ ---------- ------------
Total retail revenue 77,503 12.5% 68,918 4.9% 65,692
Wholesale revenue 22,029 1153.8% 1,757 4.3% 1,684
------------ ----------- ------------ ---------- ------------
Total Revenues $ 99,532 40.8% $ 70,675 4.9% $ 67,376
============ =========== ============ ========== ============
Sales (Decatherms):
Retail 14,142,782 13.3% 12,487,087 6.3% 11,749,434
Wholesale 11,738,372 1278.6% 851,459 -27.8% 1,180,072
------------ ----------- ------------ ---------- ------------
Total 25,881,154 94.0% 13,338,546 3.2% 12,929,506
------------ ----------- ------------ ---------- ------------
Average revenues per decatherm
Retail $ 5.48 -0.7% $ 5.52 -1.3% $ 5.59
Wholesale $ 1.88 -8.7% $ 2.06 44.1% $ 1.43
</TABLE>
Residential, commercial and industrial revenues increased in 1998 because
of a 4% increase in customers and colder than normal weather during the year.
The increase in wholesale revenues reflects the Company's increased focus on
this business opportunity.
Residential, commercial and industrial operating revenues increased in 1997
as a result of a 5% increase in customers. The increase in industrial revenues
was partially offset by lower use per customer. Miscellaneous revenues were
lower in 1997 because of a $1.8 million charge for customer refunds. Wholesale
revenues did not change materially in 1997.
<TABLE>
<CAPTION>
1998 1997 1996
------------------------------------ ------------------------------------ ---------------
Change from Change from
Amount Prior year Amount Prior year Amount
-------- ------------- -------- ------------- --------
<S> <C> <C> <C> <C> <C>
Water Operating Revenues $ 49,143 5.6% $ 46,519 2.6% $ 45,344
======== ========== ======== ========= ========
</TABLE>
Water revenues were higher in 1998 because of a 3% increase in customers
and an April 1998 price increase. The 1997 revenues were also higher due to a
3% increase in customers.
31
<PAGE>
<TABLE>
<CAPTION>
1998 1997 1996
------------------------------------ -------------------------------- -----------
Change from Change from
Amount Prior year Amount Prior year Amount
----------- ---------------- ----------- -------------- -----------
<S> <C> <C> <C> <C> <C>
Purchased Power $ 156,970 20.2% $ 130,612 6.8% $ 122,272
Purchased Power MWH 4,623,959 20.5% 3,836,975 0.2% 3,829,534
Average cost per MWH of
Purchased Power $ 33.95 -0.3% $ 34.04 6.6% $ 31.93
</TABLE>
Purchased power costs were significantly higher in 1998 due mostly to the
costs associated with higher wholesale electric sales as discussed previously.
To a lesser extent system load growth also contributed to higher purchased power
costs.
Purchased power costs increased in 1997 due to higher costs per MWH because
of the reduced availability of low cost hydropower. As a result, the Company
only slightly increased the volume of electricity purchased, and instead
increased its generation to meet the growing demand.
<TABLE>
<CAPTION>
1998 1997 1996
----------------------------------------- ----------------------------------- -----------
Change from Change from
Amount Prior year Amount Prior year Amount
----------- -------------- ----------- -------------- -----------
<S> <C> <C> <C> <C> <C>
Fuel for Power Generation $ 114,803 13.8% $ 100,861 -1.7% $ 102,601
MWHs generated 5,524,262 13.7% 4,859,203 4.1% 4,668,598
Average cost per MWH of
Generated Power $ 20.78 0.1% $ 20.76 -5.6% $ 21.98
</TABLE>
The costs of fuel for generation increased in 1998 because of higher
generation requirements needed to meet continued customer growth and greater use
per customer.
The cost of fuel for generation decreased slightly in 1997 due to the
Company's purchase of lower-cost spot coal and the operation of Pinon Pine Power
Project using natural gas. These decreases were partially offset by the
requirement to increase generation to meet continued growth.
32
<PAGE>
<TABLE>
<CAPTION>
1998 1997 1996
----------------------------- ------------------------------ ------------
Change from Change from
Amount Prior year Amount Prior year Amount
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Gas Purchased for Resale
Retail $ 44,473 21.2% $ 36,703 12.9% $ 32,519
Wholesale 20,957 1371.7% 1,424 3.2% 1,380
------------ ------------ ------------ ----------- $-----------
Total $ 65,430 71.6% $ 38,127 12.5% $ 33,899
============ ============ ============ =========== ============
Gas Purchased for Resale (decatherms)
Retail 14,462,505 13.6% 12,727,950 7.6% 11,833,519
Wholesale 11,738,372 1278.6% 851,459 -27.8% 1,180,072
------------ ------------ ------------ ----------- ------------
Total 26,200,877 92.9% 13,579,409 4.3% 13,013,591
============ ============ ============ =========== ============
Average cost per decatherm
Retail $ 3.08 6.9% $ 2.88 4.7% $ 2.75
Wholesale $ 1.79 7.2% $ 1.67 42.7% $ 1.17
</TABLE>
Consistent with the increase in retail gas revenues from customer growth
and colder weather in 1998, retail gas purchases (decatherms) were higher in
1998. The average cost per decatherm for all purchases was also higher because
of an increase in the unit cost of firm and spot purchases. 1997 costs were
higher for the same reasons that applied to the 1998 increases (customer growth
and higher unit costs).
<TABLE>
<CAPTION>
1998 1997 1996
------------------------------ ----------------------------------- -----------------
Change from Change from
Amount Prior year Amount Prior year Amount
-------- ------------- -------- ------------ -------
<S> <C> <C> <C> <C> <C>
Allowance for other funds used
during construction $ 3,797 -33.7% $ 5,723 9.4% $ 5,231
Allowance for borrowed funds used
during construction 6,414 34.0% 4,785 21.9% 3,924
-------- --------- -------- --------- -------
$ 10,211 -2.8% $ 10,508 14.8% $ 9,155
-------- --------- -------- --------- -------
</TABLE>
The total allowance for funds used during construction (AFUDC) was slightly
lower in 1998 than 1997. The 1998 amount was lower due to the completion of the
Pinon Pine power project in June 1998. AFUDC in 1997 exceeded the 1996 level
primarily as a result of higher work in progress balances for the Alturas
intertie project.
33
<PAGE>
<TABLE>
<CAPTION>
1998 1997 1996
----------------------------- ------------------------------ ---------
Change from Change from
Amount Prior year Amount Prior year Amount
--------- ------------- --------- ------------- ---------
<S> <C> <C> <C> <C> <C>
Other operating expense $ 116,076 -3.8% $ 120,600 -1.0% $ 121,798
Maintenance expense 22,266 -4.8% 23,387 13.1% 20,672
Depreciation and amortization 69,435 8.3% 64,117 10.3% 58,118
Income taxes 43,550 7.8% 40,387 11.4% 36,241
Interest charges on long-term debt 38,890 -1.8% 39,609 6.9% 37,051
Interest charges- other 7,659 67.1% 4,583 0.1% 4,579
Preferred dividend requirements of
company-obligated preferred securities 4,171 0.0% 4,171 138.5% 1,749
</TABLE>
Other operating expense was lower in 1998 due to lower costs for stock
compensation, post-retirement benefits, fuel buyouts, lower accruals for delays
in the construction of Pinon, and no flood damage costs. Other operating
expense for 1997 decreased primarily as a result of early retirement and
severance costs incurred in 1996 but not in 1997. The 1997 decrease was offset
by expenses incurred by the Pinon subsidiaries, an accrual for delays in
construction of Pinon, increased fuel buyouts and flood related costs.
Maintenance expense was lower in 1998 because of additional electric plant
maintenance performed during the previous year. Maintenance expense for 1997
increased primarily as a result of costs incurred for the repair and replacement
of facilities damaged during a flood that occurred in January 1997, and for the
cost of more extensive plant outages than occurred in 1996.
Depreciation expense increased in 1998 because of additional Pinon Pine
facilities placed in service in June 1998. Also, 1998 depreciation was higher
due to water division additions and other customer improvements added to plant
in service late in 1997. Depreciation increased in 1997 primarily as a result
of new facilities being placed in service. The Chalk Bluff water treatment
plant and the Pinon Pine power island were placed in service in 1997. In
addition, the combustion turbines at Clark Mountain received authorization to be
utilized for more hours of generation, as opposed to merely peaking units. The
greater expected utilization reduced the estimated service lives of the units
and increased depreciation expense. Continued normal additions to the utility
plant contributed to the 1996 increase.
Operating income taxes increased in 1998 due to increases in pre-tax income
and the effective tax rate. Operating income taxes increased in 1997 as a
result of improved pre-tax income. See Note 6 for more information.
Interest on long-term debt was lower in 1998 because of the redemption of
$5 million of 8.65% medium-term notes on June 18, 1998. In 1997, interest on
long-term debt increased, reflecting the effect of interest on debt issued
during 1996 that was outstanding for all of 1997.
Interest charges-other increased in 1998 because of higher short-term debt
balances utilized to partially finance the Alturas transmission project.
Due to the issuance in the third quarter of 1996 of 8.6% trust originated
preferred securities by the Company's subsidiary, Sierra Pacific Power Capital
I, preferred dividends on mandatorily redeemable preferred securities increased
in 1997.
34
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
Construction Expenditures and Financing
- ---------------------------------------
The table below provides cash construction expenditures and net internally
generated cash for 1996 through 1998 (dollars in thousands):
<TABLE>
<CAPTION>
1998 1997 1996 TOTAL
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Cash Construction Expenditures $139,098 $110,878 $179,101 $429,077
============ ============ ============ ============
Net cash flow from operating activities $153,191 $145,455 $110,666 $409,312
Less common and preferred cash dividends
paid 80,459 75,459 69,559 225,477
------------ ------------ ------------ ------------
Internally generated cash 72,732 69,996 41,107 183,835
Add equity contribution from parent 17,250 27,000 36,000 80,250
------------ ------------ ------------ ------------
Total cash available $ 89,982 $ 96,996 $ 77,107 $264,085
============ ============ ============ ============
Internally generated cash as a percentage
of cash construction expenditures 52% 63% 23% 43%
Total cash available as a percentage of cash
construction expenditures 64% 87% 43% 61%
</TABLE>
The Company's estimated construction expenditures for 1999 through 2003 are
$640 million. The Company estimates that 63% of its 1999 cash expenditures of
approximately $113 million will be provided by internally generated funds, with
the remainder being provided by the issuance of long-term and short-term debt.
The anticipated level of internally generated cash utilized for
construction of 63% anticipates that the Company will pay all of its net income
in dividends to Sierra Pacific Resources. The Company anticipates receiving $26
million of common equity contribution from Sierra Pacific Resources in 1999.
Capital Structure
- -----------------
In January of 1998 the Company revised its credit facilities resulting in a
$150 million 364-day credit facility for the Alturas project, and a $50 million
revolving credit facility to support commercial paper activity. The $150
million Alturas credit facility was used primarily to finance the construction
of the Alturas Intertie Project and the facility expired on January 29, 1999.
The Company utilized $105 million of the facility during 1998. Facility fees
for 1998 were approximately $120,000 for the Alturas Credit Facility, and
$60,000 for the revolving credit facility. Facility fees for 1997 were
approximately $110,000.
As of December 31, 1998 the Company had no commercial paper outstanding.
The Company's commercial paper is rated P2, A2 by Moody's and Standard and
Poor's, respectively.
On January 29, 1999, the Company established a new $150 million unsecured
credit facility for general corporate purposes. This credit facility will expire
on December 31, 1999. SPPC pays the lender a facility fee on the commitment
quarterly, in arrears.
35
<PAGE>
The Company's actual capital structure at December 31, 1998, 1997, and 1996
was as follows (dollars in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Short-Term Debt (1) $ 135,473 9% $ 75,454 6% $ 53,434 4%
Long-Term Debt 606,450 40% 606,889 42% 607,287 44%
Preferred Stock 121,615 8% 121,615 8% 121,615 9%
Common Equity 661,367 43% 639,556 44% 606,896 43%
---------- ---- ---------- ---- ---------- ----
$1,524,905 100% $1,443,514 100% $1,389,232 100%
========== ==== ========== ==== ========== ====
</TABLE>
(1) Including current maturities of long-term debt and preferred stock.
The indenture under which the Company's first mortgage bonds are issued
prescribes certain coverage ratios that must be met before additional bonds may
be issued. At December 31, 1998, these coverage provisions would allow for the
issuance of approximately $621.9 million in additional first mortgage bonds at
an assumed interest rate of 8%. The indenture also limits the amount of first
mortgage bonds that the Company may issue to 60 percent of unfunded property
plus the amount of any previously issued bonds which have since been retired.
Based on certifications to the trustee as of December 31, 1998, these indenture
provisions would have allowed for the issuance of approximately $705.7 million
in additional first mortgage bonds.
The Company's long-term debt is rated A3, A- by Moody's and Standard &
Poor's, respectively. The Company's pre-tax interest coverages for 1998, 1997
and 1996 were 3.87%, 3.86% and 3.65%, respectively.
In December 1998 the Company issued $35 million of collateralized debt
securities, previously registered in December 1996.
On November 12, 1998 SPPC's board of directors declared a common dividend
of $19.0 million, payable on or before February 1, 1999, and a preferred
dividend of $1.4 million payable on or before March 1, 1999. On February 22,
1999 the SPPC board declared both a common dividend of $19.0 million and
preferred dividends of $1.4 million payable on or before May 1, and June 1,
1999, respectively.
REGULATORY
Nevada Matters
- --------------
The Nevada Legislature passed Assembly Bill 366 (AB 366) and Governor Miller
signed it into law on July 16, 1997. This law establishes the framework for
competition in the electric and gas industries in Nevada.
In August 1997, the Public Utilities Commission of Nevada (PUCN) opened an
investigatory docket on the following issues to be considered as a result of
restructuring of the electric industry.
(1) Identification of all cost components in utility service and establishment
of allocation methods necessary for later pricing of noncompetitive
services;
(2) Designation of services as potentially competitive or noncompetitive;
(3) Determination of rate design and non-price terms and conditions for
noncompetitive services;
(4) Establishment of licensing requirements for alternative sellers of
potentially competitive services;
(5) Past (stranded) costs;
(6) Criteria and standards by which the PUCN will apply the legislative
requirements concerning affiliate
36
<PAGE>
relations;
(7) Criteria and standards by which the PUCN will appoint providers of bundled
electric service;
(8) Consumer protection;
(9) Anti-competitive behavior codes of conduct and enforcement;
(10) Price regulation for potentially competitive services in immature markets;
(11) Compliance plans in accordance with regulation;
(12) Options for complying with legislative mandates for integrated resource
planning and portfolio standards; and,
(13) Innovative pricing for noncompetitive services.
Highlights of restructuring activity follow:
Identification of Cost Components
On November 5, 1997, the PUCN issued an order containing the approved list
of electric services for unbundling. In order to establish rates for the
provision of electric services in a restructured environment, Sierra's existing
rates will need to be separated, or unbundled, into "potentially competitive"
and "non-competitive" functional categories. The PUCN has identified 26 such
categories of electric service.
In November 1997, Sierra and Nevada Power filed testimony and reports on
electric unbundling methodologies. The PUCN held a hearing on the filings. As
a result of the hearing, all parties were instructed to work towards consensus
on the methodologies. Unbundling Consensus Report No. 2 was filed by Nevada
Power on March 19, 1998 on behalf of all parties and reported that consensus was
reached on all remaining issues.
Designation of Services as Potentially Competitive or Noncompetitive
On August 20, 1998 the PUCN issued a final order designating certain
services as potentially competitive or noncompetitive. The PUCN deemed that
generation and aggregation had already been designated potentially competitive
as a result of AB366. Additionally, the PUCN deemed customer services,
metering, and billing as potentially competitive services. However, the PUCN
also authorized the regulated electric distribution utility to provide billing
and customer service to its customers (i.e. alternative sellers) for any
services provided to those customers.
Distribution Non-price Terms and Conditions
The PUCN issued an order adopting final regulations for non-price terms and
conditions of distribution services on January 7, 1999. In this order, the PUCN
delineated the roles and responsibilities of the electric distribution utility
and the alternative sellers for various processes and procedures including new
service connections, change orders, basic maintenance processes, etc.
Licensing of Alternative Sellers and Consumer Protection Requirements for
Alternative Sellers
The PUCN issued proposed rules on licensing of alternative sellers and
consumer protection requirements for alternative sellers. These rules provide
the licensing and reporting requirements of alternative sellers and establish
the conduct required when alternative sellers provide generation or aggregation
services to residential and small commercial customers.
37
<PAGE>
The Company filed comments and attended hearings on the proposed rules
during September, October, and November. On November 13, 1998 the PUCN adopted
a final rule for consumer protection and voted to reissue the licensing rule for
further comment. The PUCN adopted a final licensing rule on January 7, 1999.
Past Costs
Past costs, commonly referred to as stranded costs in other jurisdictions,
are an element of restructuring that will be addressed in 1999. AB366 defines
the legislative criteria which must be met in order to recover past costs. The
PUCN has not yet adopted any administrative regulations on the subject, although
several workshops have been held. Topics addressed in the workshops include the
characteristics that define recoverable past costs, criteria for evaluating the
effectiveness of mitigation efforts, options for cost recovery mechanisms and
identification of applicable tax and accounting issues.
On December 28, 1998, the Commission issued a proposed rule that specifies
the information requirements a utility must include in its request for recovery
of past costs. Comments on the proposed rule were due January 25, 1999. The
Commission conducted the rulemaking hearing on January 28, 1999, and is expected
to issue a final rule shortly. The final rule will establish the date for a
filing to recover past costs.
The Company has not released an estimate of its past costs, since such a
calculation is dependent on a variety of issues related to restructuring which,
at this time, are not fully resolved.
Affiliate Transaction Rules
On December 18, 1998, the PUCN issued a final rule dealing with business
transactions between regulated electric and gas distribution companies and
affiliates providing potentially competitive services. The rule includes a
prohibition on the use of the corporate utility name and logo by affiliates.
Any statement of affiliation to the regulated distribution company used by an
affiliate must include a lengthy and no less prominently displayed disclaimer.
The rule also prohibits the sharing of corporate services without prior PUCN
approval.
Provider of Last Resort
The provider of last resort (PLR) will provide electric service to
customers who choose not to choose and to customers who are not able to obtain
service from an alternative seller. There have been several workshops and
hearings held on the PLR issue and more discussion of the issue is anticipated.
A final order is expected sometime early in 1999.
ISA, Load Pockets and Generation Aggregation Tariff
The move to retail competition in various states has included the
establishment of an entity to ensure reliable operation of transmission systems
and to assure equal and non-discriminatory access to those systems by all
alternative sellers. In California, an independent system operator (ISO) was
established. An ISO was also established in the Midwest. Similar to a proposal
being developed in Arizona, Nevada stakeholders are pursuing the development of
an interim independent scheduling administrator (ISA) to address these functions
as part of the move to retail open access in Nevada. In time, it is expected
that regional entities, either ISO's or independent transmission companies
(Transcos) will be established to perform these functions. The Company
therefore considers the ISA to be an interim solution that would facilitate
retail open access in Nevada while
38
<PAGE>
regional solutions develop. The PUCN issued an order providing guidance to the
parties on the development of an interim ISA on October 12, 1998. The parties,
including the Company, began a consensus process to develop the ISA. The efforts
of the established working group continue. An ISA proposal is expected to be
filed with FERC in April 1999.
A workshop on generation tariffs was held in November and proposals from
the Company/Nevada Power and PUCN staff were discussed. Subsequently, PUCN
staff filed a proposed tariff with the PUCN. The Company and other parties have
filed comments on these proposed tariffs. A key issue is whether the tariff
should be market based or cost based. The tariffs were discussed with FERC
Trial Staff in January 1999. Based on this feedback, the Company is planning
not to proceed with the PUCN Staff's proposal, but a cost-based tariff instead.
This tariff is expected to be filed with FERC in March 1999.
Compliance Plans
The Company will prepare a compliance filing showing unbundled costs of
service and proposing rates for the non-competitive categories. This filing is
expected to be submitted to the PUCN in the Spring of 1999.
Gas Restructuring
In order to comply with Nevada AB 366 for natural gas deregulation, the
PUCN is developing new natural gas rules. The PUCN is following similar
processes as in electric restructuring to develop new rules.
To date the PUCN has developed a list of unbundled services and has adopted
a proposed rule for declaring services potentially competitive. This rule
provides the process to be followed to declare services to be potentially
competitive and does not apply to services for large commercial and industrial
customers which are already eligible for competitive services such as Incentive
Natural Gas Rate (INGR), Value Based Service Tariff (VBST), and transportation.
The PUCN has also obtained comments, developed a proposed rule, and held
workshops on licensing requirements for alternative sellers. This rule is
expected to be adopted in the near future.
California Matters
- ------------------
Direct Access Implementation Plan
The Company filed an Advice Letter in February 1998 which contained
proposed tariff changes to implement direct access. These changes were in
response to the California Public Utilities Commission (CPUC) order on the
Company's Direct Access Implementation Plan which was approved on October 30,
1997.
10% Rate Reduction and Revenue Reduction Bond Filing
In June 1998, the Company filed for Rate Reduction Bonds in order to
recover the cost of the mandated 10% rate reduction. The Company requested
approval to issue up to $25 million in revenue reduction bonds. At the
suggestion of the CPUC, after the defeat of Proposition 9, the Company filed a
Petition for Modification of the Transition Plan Order and requested balancing
account treatment in lieu of revenue reduction bonds in September. On December
17, 1998 the CPUC denied the Company's Petition for Modification of the
Transition Plan Order. The Company anticipates issuing Rate Reduction Bonds
during the second quarter of 1999.
39
<PAGE>
Rate Unbundling
The Company filed an Advice Letter in February 1998 which contained
proposed unbundled rates to be implemented June 1, 1998. The Company also filed
its proposal for implementing the three billing options and for revenue cycle
unbundling. These filings were in response to the CPUC's order on the Company's
Transition Plan. In August, the Company filed its Revenue Cycle Unbundling
Proposal. Revenue cycle services include meter ownership, meter services (O&M),
meter reading, and billing. Under the Company's proposal, customers who select
their own provider of a revenue cycle service would receive a credit on their
bill.
Transition Costs, Stranded Costs, and Market Valuation
On June 30, 1998, the Company requested an extension for California market
valuation of generation assets. The Company requested an extension until July 1,
1999, to file its proposed mechanism for establishing the market value of its
generation assets. The Transition Plan order required the Company to file this
proposal on July 1, 1998. The CPUC granted the Company a 90-day extension to
file an application proposing a mechanism for valuing its generation assets on
July 6, 1998. The Company requested the extension to allow more time for the
PUCN to develop its approach, so a consistent approach could be used. In
granting the extension, the CPUC directed the Company to encourage the PUCN to
develop an approach during the 90-day extension period. The 90-day extension
period expired without the Company making the filing. The Company continues to
work with the PUCN and anticipates that a mechanism to establish generation
market value will be developed by the third quarter of 2000.
Affiliate Transaction Rules
The CPUC denied the Company's December 30, 1997 request for an extension on
filing its Affiliate Transaction Compliance Plan. However, the CPUC did extend
the date for full compliance. The Company filed its Affiliate Transaction
Compliance Plan in February 1998 in an Advice Letter.
In response to petitions for modification of its December 16, 1997
Affiliate Transaction Rule order, the CPUC revised and clarified portions of its
affiliate transaction rules. The revisions include the following:
. Allows a "narrow" exception to the rules, which did not permit a utility to
temporarily assign its employees to affiliates. The rules now permit the
utility to make temporary or intermittent assignments or rotations of utility
employees, except those employees involved in marketing, to its affiliates
covered by these rules, except to the utility's energy marketing affiliates,
under specific conditions contained in the rules.
. Provides the utility an opportunity to demonstrate that no fee, or a lesser
percentage than 15%, is appropriate for rank-and-file (non-executive)
employees whose positions are impacted as a result of electric industry
restructuring, under specific conditions contained in the rules.
. The decision clarifies the existing rules regarding corporate oversight and
governance.
. Modifications to the utility products and services section.
. Modifications to the timing of the compliance audit and regarding service
provider information.
On December 19, 1998 the CPUC adopted a final rule on enforcement and
penalties. The rule contains provision for enforcing the affiliate transaction
rules and penalties for violating the rules.
40
<PAGE>
Consumer Protection
The CPUC issued the Consumer Protection Decision on March 26, 1998. The
CPUC adopted rules to ensure consumers are protected from unfair marketing
practices and that Energy Service Providers (ESPs) demonstrate their
creditworthiness and technical expertise to engage in power sales to the public
as the state's electricity industry is opened to competition. The rules were
adopted pursuant to Senate Bill 477 and applied to currently registered ESPs and
those seeking registration. Registered ESPs had until June 24, 1998 to comply
with the revised requirements, face suspension for non-compliance, or request
inactive status by April 15, 1998. The interim standards that ESPs must follow
will remain in effect until permanent standards are adopted.
In addition, Consumers who do not want ESPs to solicit them by telephone
can ask to be placed on a "Don't Call Me list." Any ESP who solicits a customer
on the list more than once is liable to the customer for $25 for each contact.
ESPs are prohibited from using the list for mailing purposes. A separate "Opt-
In" list for those who want to be contacted by ESPs may be developed if there is
consumer and energy service provider demand for one.
FERC Matters
On May 22, 1998, the Company and several other parties filed a "Petition
for Review" with the D.C. Court of Appeals requesting review of the FERC's
decisions in the Pacific Gas Transmission (PGT) rate case. The FERC had
previously denied the Company's protest of a settlement in PGT's last rate case
and the Company's request for rehearing.
On July 9, 1998, the Administrative Law Judge (ALJ) certified the
settlement reached in the Import Limit Case (Dockets ER97-3593 and ER97-4462).
The settlement resolves all issues in these cases and provides for a
continuation of the current import limit allocation until the Alturas Inter-tie
is in service. At that time and until February 28, 2001, Truckee Donner Public
Utility District (TDPUD) will receive 30 MW of import capability. After
February 28, 2001, allocation of import capacity will be determined by the FERC
based on the results of the Company's 1998 PUCN resource plan and a subsequent
filing with the FERC in 1999. The settlement now goes to the FERC for approval.
Truckee-Carson Irrigation District (TCID) has contested the settlement; however,
the ALJ certified the settlement since the opposition by TCID does not raise
issues of material fact.
On October 2, 1998, the Company and Nevada Power filed an application with the
FERC for merger approval. In a separate, concurrent filing, the companies
submitted an open access transmission tariff for the merged company.
The FERC issued an order requiring additional minor changes to the
Company's standards of conduct and related posting on OASIS in October. On
November 2, 1998 the FERC issued a letter order approving the Retail Tariff
Settlement between the Company and FERC Staff. Also, on November 30th, the FERC
issued an order accepting the Alturas interconnection and O&M agreement between
the Company and Bonneville Power Administration. The order requires the Company
to work with the WSCC members to establish operating procedures to avoid
impacting the reliability of other systems.
The Company filed an Operating Agreement for the Alturas Inter-tie Project
with FERC on December 22, 1998. The Operating Agreement is a three-way
agreement between the Company, Bonneville Power Administration and PacifiCorp.
41
<PAGE>
Year 2000 Issues
To the maximum extent permitted by applicable law, the following
information is being designated as a "Year 2000 Readiness Disclosure" pursuant
to the "Year 2000 Information and Readiness Disclosure Act" which was signed
into law on October 19, 1998.
The Company uses business application software programs and relies on
computing infrastructure that includes embedded systems that have a Year 2000
(Y2K) affect on the Company. In many cases, the Company's software programs and
embedded systems use two-digit years that may recognize a date using `00' as the
year 1900 rather than the year 2000. This could result in the computer or device
shutting down, performing incorrect computations, or performing in an
inconsistent manner.
In 1996 the Company established its Y2K project to address the Y2K issues.
The project's scope includes: (1) business application systems including, but
not limited to, customer information and billing and financial systems
including; time reporting, payroll, general ledger, accounts payable and
purchasing, and end-user developed systems; (2) embedded systems, including
equipment that operates or controls operating facilities including power plants,
electric transmission and distribution, water, gas, telecommunications, and
information technology systems; (3) customer, vendor, and supplier
relationships; and (4) testing and contingency planning.
To implement its Y2K strategies, the Company established a Y2K project
office currently headed by the Chief Financial Officer. This office includes an
oversight committee representing all lines of business, and a "champions team"
representing electric generation, transmission and distribution, gas
distribution, water production and distribution, telecommunications, systems
control, computer infrastructure and building facilities. Also represented are
Internal Audit, Engineering, Procurement, Legal, and Human Resources. In
addition, the Company has utilized the expertise of outside consultants to
assist in the project management and the technical aspects of the project.
Business Application Systems
The initial focus for the Y2K project team was on the business application
systems. In the fall of 1996 the Company purchased software assessment tools and
completed its inventory and code assessment for its mainframe business systems.
The inventory is comprised of over 7 million lines of COBOL code, and end-user
programs.
The Company developed and strictly adheres to a Y2K methodology that
includes, unit, system wide and Y2K date specific testing.
The first major Y2K ready business system, Customer Information and Billing
representing more than 2 million lines of code, was successfully implemented in
June, 1997. As of this date, the Company has successfully implemented 95% of its
business systems and has a target completion date of March, 1999 to complete all
systems. The Company is on schedule to meet that date.
Embedded Systems
The Company hired an outside engineering consultant, Network Systems
Engineering Corporation (NSEC), to assist the Company's staff in conducting a
thorough and comprehensive inventory of its embedded systems at the component
level. All systems have been inventoried and assessed. This inventory identified
over
42
<PAGE>
2,500 potentially date sensitive items. The Company and NSEC have contacted all
manufacturers of those components that they have identified as critical to
operations and continue to contact other manufacturers of embedded system
components to determine if their components are Y2K ready. As of December 31,
1998, 11% of the embedded systems components are not ready, 25% need further
assessment, and 64% are ready or not date sensitive. Testing is underway for
those items that are critical to the Company's business continuation.
In order for systems to be considered Y2K ready each have undergone the
phases of inventory, analysis, correction, testing and implementation. The
following chart summarizes the Company's expected preparedness by quarter for
1999.
<TABLE>
<CAPTION>
Systems 1st qtr 2nd qtr
- ----------------------------------------
<S> <C> <C>
Electric 37% 100%
- ----------------------------------------
Natural gas 50% 100%
- ----------------------------------------
Water 50% 100%
- ----------------------------------------
Business 100% 100%
Systems
- ----------------------------------------
</TABLE>
The North American Electric Reliability Council expects utilities to have
all Y2K testing and remediation complete by June 30, 1999. The Company is trying
to minimize outages to its customers by scheduling some Y2K testing and
remediation around planned plant maintenance that will occur during non-peak
generating periods in the spring of 1999. The Company's embedded systems
remediation plans call for all Y2K corrective procedures to be complete by June
1999.
Vendors and Suppliers
The Company has contacted in writing all vendors and suppliers of products
and services that it considers critical to its operations. These contacts have
included, but were not limited to, suppliers of interstate transportation
capacity for coal supplies, natural gas producers, financial institutions, and
telephone service providers. The quality of responses is not uniform or
consistent. The next step is to work with the major vendors and suppliers to
assess their Y2K readiness. The Company may consider new business and
procurement alternatives for products and services as necessary to the extent
that alternatives are available.
Major Customers
The Company has met face to face with some of its major customers to share
its progress on Y2K. Also discussed at these meetings is the customer's Y2K
readiness. The Company will continue to keep its major customers informed as to
its progress on Y2K remediation, testing and contingency planning.
Contingency Planning
The Company's Y2K strategies include contingency planning for both business
and embedded systems. The planning effort includes critical Company areas such
as information technology, networks, vendors and suppliers, and operations
personnel. Quick action response teams and additional Company personnel are
planned to be available for the century rollover. Specific contingency plans are
being developed with a completion date for all plans by the end of the 2nd
quarter of 1999.
43
<PAGE>
As part of its normal business practice, the Company maintains plans to
follow during emergency circumstances, some of which could arise from Y2K
problems. Presently, the Company continues to develop and refine its contingency
plans for potential Y2K related problems.
Potential Risks
With respect to its internal operations, those over which the Company has
direct control, the Company believes the most significant potential risks are:
(1) its ability to use electronic devices to control and operate its generation,
gas, water, telecommunication, transmission and distribution systems; (2) its
ability to render timely bills to its customers; and (3) the ability to maintain
continuous operations of its computer systems.
The Company depends upon external parties, including customers, suppliers,
business partners, gas and electric system operators, government agencies, and
financial institutions to reliably deliver their products and services. The
Company feels that its most reasonable likely worst case scenario is dependent
on the extent to which any of these parties experience Y2K problems in their
system. Should any of these critical vendors fail, the impact of any such
failure could become a significant challenge to the Company's ability to meet
the demands of its customers. Business continuity interruption could also have
a material adverse financial impact, including but not limited to, lost sales
revenues, increased operating costs, and claims from customer related business
interruptions. Based upon the information supplied to date by our critical
vendors and suppliers, the Company believes the probability of such failures is
low. The Company is monitoring the progress of these critical entities and the
Company's contingency plans are addressing the potential failure of an external
party to be Y2K ready.
Financial Implications
To complete its Y2K program, the Company expects to incur expenses of
approximately $2.8 million in operations and maintenance (O&M) expenditures to
correct its business systems and $3.0 million to correct its embedded systems.
In addition, $3.4 million will be spent on capital expenditures for the embedded
systems.
These expenditures will occur over a three-year period ending in June 1999.
From the project's inception through December 31, 1998, the Company has expended
approximately $2.1 million on its business systems and $0.4 million on its
embedded systems.
The Company's Y2K program is progressing and the Company believes it is
taking all reasonable steps necessary to be able to operate successfully through
and beyond the turn of the century.
44
<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company has evaluated its risk related to financial instruments whose
values are subject to market sensitivity. The only such instruments are
Company issued fixed-rate and variable-rate debt obligations which were as
follows as of December 31, 1998:
Long-term debt (Dollars in Thousands):
<TABLE>
<CAPTION>
Expected Weighted
Expected Maturity Average
Maturity Date Amounts Interest Rates Fair Value
- --------------- ---------------- ---------------- ----------------
Fixed Rate
<S> <C> <C> <C>
1999 $ 30,500 6.88%
2000 300 9.00%
2001 17,200 5.51%
2002 200 9.00%
2003 18,200 5.60%
Thereafter 490,500 6.83%
---------------- ----------------
Total $556,900 $592,373
======== =============
Variable Rate
Due 2020 $ 80,000 *3.55% $ 80,000
======== =============
</TABLE>
* Weighted daily average rate for month ended December 31, 1998.
45
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Accountants........................................ 47
Financial Statements:
Consolidated Balance Sheets as of December 31, 1998 and 1997......... 48
Consolidated Statements of Income for the Years Ended December 31,
1998, 1997 and 1996................................................ 49
Consolidated Statements of Common Shareholder's Equity for the
Years Ended December 31, 1998, 1997 and 1996....................... 50
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996................................... 51
Consolidated Statements of Capitalization as of December 31, 1998
and 1997........................................................... 52
Notes to Consolidated Financial Statements............................... 53
</TABLE>
46
<PAGE>
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, 1998 and 1997, and the related consolidated statements of
income, common shareholder's equity, and cash flows for each of the three years
in the period ended December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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, 1998
and 1997, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998 in conformity with generally
accepted accounting principles.
DELOITTE & TOUCHE LLP
Reno, Nevada
January 29, 1999
(February 12, 1999 as to Notes 1 and 3)
47
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
<TABLE>
<CAPTION>
December 31,
ASSETS 1998 1997
------ ------------------- ------------------
<S> <C> <C>
Utility Plant, at Original Cost:
Plant in service $2,348,996 $2,063,269
Less accumulated provision for depreciation 727,624 664,490
---------- ----------
1,621,372 1,398,779
Construction work in progress 55,670 202,036
---------- ----------
1,677,042 1,600,815
---------- ----------
Other Investments 34,022 26,791
---------- ----------
Current Assets:
Cash and cash equivalents 15,197 6,920
Accounts receivable less provision for
Uncollectible accounts: 1998 - $3,461; 1997 - $1,704 114,380 104,926
Materials, supplies and fuel, at average cost 25,776 25,255
Other 2,692 2,572
---------- ----------
158,045 139,673
---------- ----------
Deferred Charges:
Regulatory tax asset 65,619 66,563
Other regulatory assets 61,675 63,476
Other 15,417 14,924
---------- ----------
142,711 144,963
---------- ----------
$2,011,820 $1,912,242
========== ==========
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common shareholder's equity $ 661,367 $ 639,556
Preferred stock 73,115 73,115
Preferred stock subject to mandatory redemption:
Company-obligated mandatorily redeemable preferred securities of
the Company's subsidiary trust, Sierra Pacific Power Capital I,
holding solely $50 million principal amount of 8.6% junior
subordinated debentures of the Company, due 2036 48,500 48,500
Long-term debt 606,450 606,889
---------- ----------
1,389,432 1,368,060
---------- ----------
Current Liabilities:
Short-term borrowings 105,000 75,000
Current maturities of long-term debt 30,473 454
Accounts payable 66,032 63,088
Accrued interest 7,535 6,394
Dividends declared 20,365 19,365
Accrued salaries and benefits 12,131 14,978
Other current liabilities 27,759 19,209
---------- ----------
269,295 198,488
---------- ----------
Deferred Credits:
Accumulated deferred federal income taxes 161,697 162,627
Accumulated deferred investment tax credits 37,944 39,873
Regulatory tax liability 38,939 40,767
Accrued retirement benefits 42,560 37,456
Customer advances for construction 34,961 38,478
Other 36,992 26,493
---------- ----------
353,093 345,694
---------- ----------
Commitments and Contingencies (Notes 3 and 13) $2,011,820 $1,912,242
========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
48
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Operating Revenues:
Electric $585,657 $540,346 $507,004
Gas 99,532 70,675 67,376
Water 49,143 46,519 45,344
--------------- --------------- ---------------
734,332 657,540 619,724
--------------- --------------- ---------------
Operating Expenses:
Operation:
Purchased power 156,970 130,612 122,272
Fuel for power generation 114,803 100,861 102,601
Gas purchased for resale 65,430 38,127 33,899
Deferral of energy costs-net - 8 (1,736)
Other 116,076 120,600 121,798
Maintenance 22,266 23,387 20,672
Depreciation and amortization 69,435 64,117 58,118
Taxes:
Income taxes 43,550 40,387 36,241
Other than income 19,608 19,269 18,851
--------------- --------------- ---------------
608,138 537,368 512,716
--------------- --------------- ---------------
Operating Income 126,194 120,172 107,008
--------------- --------------- ---------------
Other Income:
Allowance for other funds used during construction 3,797 5,723 5,231
Other income-net 335 810 867
--------------- --------------- ---------------
4,132 6,533 6,098
--------------- --------------- ---------------
Total Income Before Interest Charges 130,326 126,705 113,106
--------------- --------------- ---------------
Interest Charges:
Long-term debt 38,890 39,609 37,051
Other 7,659 4,583 4,579
Allowance for borrowed funds used during
construction and capitalized interest (6,414) (4,785) (3,924)
--------------- --------------- ---------------
40,135 39,407 37,706
--------------- --------------- ---------------
Income Before Dividends on Mandatorily Redeemable
Preferred Securities 90,191 87,298 75,400
Preferred dividend requirements of company-obligated
mandatorily redeemable preferred securities (4,171) (4,171) (1,749)
--------------- --------------- ---------------
Income Before Preferred Dividend requirements 86,020 83,127 73,651
Preferred dividend requirements (5,459) (5,459) (6,300)
--------------- --------------- ---------------
Income Applicable to Common Stock $ 80,561 $ 77,668 $ 67,351
=============== =============== ===============
</TABLE>
The accompanying notes are an integral part of the financial statements.
49
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(Dollars in Thousands)
<TABLE>
<CAPTION>
Year ended December 31,
1998 1997 1996
---------------- ---------------- ----------------
Common Stock
- ------------
<S> <C> <C> <C>
Balance at Beginning of Year
and End of Year $ 4 $ 4 $ 4
-------- -------- --------
Other Paid-In Capital
- ---------------------
Balance at Beginning of Year 545,434 518,434 482,434
Additional investment
by parent company 17,250 27,000 36,000
-------- -------- --------
Balance at End of Year 562,684 545,434 518,434
-------- -------- --------
Retained Earnings
- -----------------
Balance at Beginning of Year 94,118 88,458 84,945
Income before preferred dividends 86,020 83,127 73,651
Preferred stock dividends declared (5,459) (5,459) (5,879)
Common stock dividends declared (76,000) (72,000) (64,000)
Cost of issuing common stock
(reimbursement to parent company) - (8) (259)
-------- -------- --------
Balance at End of Year 98,679 94,118 88,458
-------- -------- --------
Total Common Shareholder's
Equity at End of Year $661,367 $639,556 $606,896
========= ========= =========
</TABLE>
The accompanying notes are an integral part of the financial statements.
50
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Cash Flows From Operating Activities:
- -------------------------------------
Income before preferred dividends $ 86,020 $ 83,127 $ 73,651
Non-Cash items included in income:
Depreciation and amortization 69,435 64,117 58,118
Deferred taxes and investment tax credits (3,743) (2,772) 1,233
AFUDC and capitalized interest (10,211) (10,508) (9,155)
Deferred energy costs - 8 (1,736)
Early Retirement and severance amortization 4,177 4,551 7,877
Merger Costs - (50) 1,909
Other non-cash 2,400 (2,109) 2,803
Changes in certain assets and liabilities:
Accounts receivable (13,836) (10,144) (3,520)
Materials, supplies and fuel (521) 2,331 2,869
Other current assets (120) 1,376 (1,602)
Accounts payable 2,944 9,090 (36,817)
Other current liabilities 6,844 1,543 12,475
Other - net 9,802 4,895 2,561
--------- --------- ---------
Net Cash Flows From Operating Activities 153,191 145,455 110,666
--------- --------- ---------
Cash Flows From Investing Activities:
- ---------------------------------------
Additions to utility plant (183,384) (147,801) (203,109)
Non-cash charges to utility plant 10,587 11,553 9,475
Customer refunds for construction (3,517) (951) (739)
Contributions in aid of construction 37,216 26,321 15,272
--------- --------- ---------
Net cash used for utility plant (139,098) (110,878) (179,101)
(Investment in) disposal of subsidiaries and
other non-utility property-net (2,788) (5,254) 681
---------- --------- --------
Net Cash Used in Investing Activities (141,886) (116,132) (178,420)
Cash Flows From Financing Activities:
- -------------------------------------
Increase (Decrease) in short-term borrowings 30,637 40,583 (16,059)
Proceeds from issuance of long-term debt 35,000 - 80,041
Retirement of long-term debt (5,456) (15,417) (427)
Decrease in funds held in trust - - 9,175
Retirement of preferred stock - - (20,400)
Proceeds from Company-obligated mandatorily redeemable
preferred securities - - 48,500
Additional investment by parent company 17,250 27,000 36,000
Dividends paid (80,459) (75,459) (69,559)
--------- --------- ---------
Net Cash (Used in) From Financing Activities (3,028) (23,293) 67,271
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 8,277 6,030 (483)
Beginning Balance in Cash and Cash Equivalents 6,920 890 1,373
--------- --------- ---------
Ending Balance in Cash and Cash Equivalents $ 15,197 $ 6,920 $ 890
========= ========= =========
Supplemental Disclosures of Cash Flow Information:
- ---------------------------------------------------
Cash Paid During Year For:
Interest $ 48,250 $ 46,824 $ 41,256
Income taxes $ 45,963 $ 41,656 $ 39,993
</TABLE>
The accompanying notes are an integral part of the financial statements.
51
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
<TABLE>
<CAPTION>
December 31,
Common Shareholder's Equity: 1998 1997
- --------------------------- ---- ----
<S> <C> <C>
Common stock, $3.75 par value,
1,000 shares authorized, issued and outstanding $ 4 $ 4
Other paid-in capital 562,684 545,434
Retained earnings 98,679 94,118
---------- ----------
Total Common Shareholder's Equity 661,367 639,556
---------- ----------
Cumulative Preferred Stock:
- --------------------------
Not subject to mandatory redemption:
$50 par value:
Series A; $2.44 dividend 4,025 4,025
Series B; $2.36 dividend 4,100 4,100
Series C; $3.90 dividend 14,990 14,990
$25 stated value:
Class A Series 1; $1.95 dividend 50,000 50,000
---------- ----------
Total Preferred Stock 73,115 73,115
Company-obligated mandatorily redeemable preferred securities of the Company'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 48,500
---------- ----------
Total preferred stock 121,615 121,615
---------- ----------
Long-Term Debt:
- --------------
First Mortgage Bonds:
Unamortized bond premium and discount, net (831) (867)
Debt Secured by First Mortgage Bonds:
2.00% Series Z due 2004 93 114
2.00% Series O due 2011 1,497 1,618
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 110,000 115,000
7.10% and 7.14% Series B MTN due 2023 58,000 58,000
6.83% and 6.86% Series C MTN due 1999 - 30,000
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 3,207 3,275
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 -
5.59% Series D MTN due 2003 13,000 -
---------- ----------
Subtotal, excluding current portion 527,047 527,257
Variable Rate Note:
Water Facilities Note: maturing 2020 80,000 80,000
Other, excluding current portion 234 499
---------- ----------
Total Long-Term Debt 606,450 606,889
---------- ----------
TOTAL CAPITALIZATION $1,389,432 $1,368,060
========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
52
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies for both utility and non-utility
operations are as follows:
General
Sierra Pacific Power Company (SPPC), a wholly-owned subsidiary of Sierra
Pacific Resources (SPR), is a regulated public utility engaged principally in
the generation, purchase, transmission, distribution, and sale of electric
energy. It provides electricity to approximately 294,000 customers in a 50,000
square mile territory including western, central, and northeastern Nevada,
including the cities of Reno, Sparks, Carson City and Elko, and a portion of
eastern California, including the Lake Tahoe area. SPPC also provides water and
gas service in the cities of Reno and Sparks, Nevada, and environs. In 1995,
SPPC formed two subsidiaries for the specific purpose of forming a partnership
to operate the Pinon Pine gasifier facility. These subsidiaries are Pinon Pine
Corporation and Pinon Pine Investment Company. In February 1999, SPPC purchased
GPSF-B which owns the portion of the gasifier facility which was not already
owned by SPPC. They are consolidated into the financial statements of SPPC,
with all significant intercompany transactions eliminated. On July 29, 1996,
SPPC formed a wholly-owned subsidiary, Sierra Pacific Power Capital I (Trust),
for the purpose of completing a public offering of trust originated preferred
securities. Refer to Note 4 of SPPC's consolidated financial statements for the
stock issuance and Note 3 for the Pinon Pine Power Project.
SPPC maintains its accounts for electric and gas operations in accordance
with the Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission (FERC) and for water operations in accordance with the Uniform System
of Accounts prescribed by the National Association of Regulatory Utility
Commissioners.
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of certain assets and
liabilities. These estimates and assumptions also affect the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of certain revenues and expenses during the reporting
period. Actual results could differ from these estimates.
Certain reclassifications have been made for comparative purposes but have
not affected previously reported net income or common shareholder's equity.
SPPC Utility Plant
In addition to direct labor and material costs, SPPC also charges to the
construction of 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.
53
<PAGE>
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
SPPC capitalizes, as part of construction costs on utility plant, an
allowance for funds used during construction (AFUDC). AFUDC represents the cost
of borrowed funds and, where appropriate, the cost of equity funds used for
construction purposes in accordance with rules prescribed by the FERC and the
PUCN. AFUDC is capitalized in the same manner as construction labor and material
costs, with an offsetting credit to "other income" for the portion representing
the use 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 rate base and in the provision for depreciation.
The AFUDC rates used during 1998, 1997 and 1996 were 7.69%, 8.30% and
8.91%, 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. The provision,
as authorized by the PUCN, for 1998, 1997 and 1996, stated as a percentage of
the original cost of depreciable property, was 3.31%, 3.16% and 3.18%,
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.
SPPC engages in short-term investment activity whenever it is deemed
beneficial. As of December 31, 1998 and 1997, SPPC's investments in money
market funds were $12.4 million and $4.7 million respectively.
Regulatory Accounting and Other Regulatory Assets
SPPC's 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, SPPC qualifies for the application of SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation". 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
54
<PAGE>
that would otherwise be charged to expense where it is probable that future
revenue will be provided to recover these costs. 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 71 discontinue the application of that statement by
eliminating the effects of any actions of regulators that had been previously
recognized.
In 1997, the Emerging Issues Task Force (EITF) released Issue 97-4. In
doing so, it reached a consensus that a utility subject to a deregulation plan
for its generation business should stop applying SFAS No. 71 to the generating
portion of its business no later than the date when a plan with sufficient
detail of the effect of the plan is known. EITF 97-4 also reached a consensus
that regulatory assets and liabilities that originated in a portion of the
business which is discontinuing its application of SFAS No. 71 should be
evaluated on the basis of where (that is, the portion of the business in which)
the regulated cash flows to realize and settle them will be derived. The result
of the consensus is that there is no elimination of regulatory assets which the
deregulatory legislation or rate order specifies collection of, if they are
recoverable through a portion of the business which remains subject to SFAS No.
71.
In conformity with SFAS No. 71, the accounting for SPPC conforms with
generally accepted accounting principles as applied to regulated public
utilities and as prescribed by agencies and the commissions of the jurisdictions
in which it operates.
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 as of December 31 (dollars in thousands):
<TABLE>
<CAPTION>
DESCRIPTION 1998 1997 AMORTIZATION PERIODS
- ----------- -------- -------- --------------------
<S> <C> <C> <C>
Early Retirement and Severance Offers $20,468 $24,644 Various through 2005
Loss on Reacquired Debt 17,918 18,354 Various through 2023
Plant Assets 7,978 8,869 Various through 2031
Conservation and Demand Side Programs 3,787 6,146 Various through 2006
Other Costs 11,524 5,463 Various
------- -------
Total $61,675 $63,476
======= =======
</TABLE>
Currently, the electric utility industry is predominately 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 SPPC's future financial
position and results of operations.
55
<PAGE>
Deferral Of Energy Costs
SPPC has suspended deferred energy accounting in its Nevada (except for
liquid propane gas) and California jurisdictions. Prior to May 1995 (Nevada) and
June 1996 (California), SPPC employed deferred energy accounting procedures in
its electric and gas operations, as provided by statutes. The intent of these
procedures was to capture fluctuations in the cost of purchased gas, fuel and
purchased power. Deferred energy accounting required SPPC to record the
difference between actual fuel expense and fuel revenues as deferred energy
costs.
In Nevada, deferred energy remains suspended until January 1, 2000. At that
time, there is a possibility of the Company returning to deferred energy
accounting.
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 the parent 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.
For regulatory purposes, SPPC is 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, SPPC 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 SPPC 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 SPPC. The deferred
investment tax credit balance is being amortized over the estimated service
lives of the related properties.
Revenues
SPPC accrues unbilled utility revenues earned from the dates customers were
last billed to the end of the accounting period. These amounts are included in
accounts receivable.
Recent Pronouncements of The FASB
In June 1998, the FASB issued SFAS 133, entitled "Accounting for Derivative
Instruments and Hedging Activities". This statement establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, (collectively referred to as
derivatives) and for hedging activities. It requires that an entity recognize
all derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value and is effective for all
fiscal quarters of all fiscal years beginning after June 15, 1999. The Company
is still assessing the impact of SFAS 133 on its financial condition and results
of operations.
56
<PAGE>
NOTE 2. REGULATORY ACTIONS
Nevada Proceedings
As a result of the 1997 rate plan, SPPC made its first earnings sharing
filing on April 29, 1998. For its electric customers, SPPC filed to refund $7.3
million based upon calendar year 1997 results. SPPC also proposed a refund of
$1.7 million to its gas division customers for results of the same period. In
December 1998, a pre-hearing conference was held which set hearings for early
1999. An order is expected before mid-year. The Company has recognized
contingent liabilities to provide for its estimate of the outcome of this
proceeding.
On April 2, 1998, the PUCN issued its order with respect to the SPPC's
application for an increase in its water division's general rates. The
application was filed in September 1997. The PUCN's decision authorized SPPC to
increase its water rates by approximately $4.3 million annually (or 9.4%),
effective April 29, 1998.
On February 27, 1998, SPPC requested permission from the PUCN to continue
to serve customers in the Truckee-Carson Irrigation District (TCID) leasehold
area upon expiration of the leasehold agreement. On September 29, 1998, the
PUCN determined that SPPC was fit, willing, and able to serve the leasehold
area. The PUCN also determined that TCID's application was deficient. However,
the PUCN will allow the TCID to reapply for a certificate sometime in the future
if it satisfies numerous conditions including obtaining a judicial determination
that it owns facilities in the area. The Company continues negotiations with
TCID.
California Proceedings
On January 1, 1998, as a result of the CPUC's December 16, 1997 Transition
Plan order, SPPC implemented a 10%, or a $2.9 million annual, rate reduction for
its residential and small commercial customers using less than 20 kw of demand
monthly.
In June 1998, SPPC filed for Revenue Reduction Bonds in order to recover
the cost of the 10% rate reduction. SPPC requested approval to issue up to $25
million in revenue reduction bonds. At the suggestion of the CPUC, after the
defeat of Proposition 9, SPPC filed a Petition for Modification of the
Transition Plan Order and requested balancing account treatment in lieu of
revenue reduction bonds in September. On December 17, 1998 the CPUC denied
SPPC's Petition for Modification of the Transition Plan Order. SPPC anticipates
issuing Revenue Reduction Bonds during the first quarter of 1999.
FERC Proceedings
On January 21, 1998, SPPC filed its compliance with the FERC's Order in
Docket No. ER98-12 (Retail Access Transmission Service). This filing contained
changes to the Open Access Transmission Tariff necessary to accommodate retail
access in SPPC's California retail jurisdiction. On April 17, 1998, a
settlement was filed resolving all outstanding issues. The settlement was
certified on May 20, 1998 and approved on November 2, 1998.
57
<PAGE>
On February 19, 1998, FERC rejected a zone pricing rate design in the
order in one of SPPC's natural gas transportation providers, Northwest Pipeline,
(Northwest) Docket No. RP94-220. All other issues in this case were previously
settled. FERC also issued an initial decision in Northwest's Docket No. RP95-
409 that covers O&M expenses, depreciation, rate of return and capital
structure, rate base adjustments, and billing determinants.
On May 22, 1998, the SPPC and several other parties filed a "Petition for
Review" with the D.C. Court of Appeals requesting review of the FERC's decisions
in the Pacific Gas Transmission (PGT), another of the SPPC's natural gas
transportation providers. The FERC had previously denied SPPC's protest of a
settlement in PGT's last rate case and the SPPC's request for rehearing.
On June 4, 1998, SPPC filed a settlement with all parties in Docket No.
ER97-3593-000 et al. The settlement resolves all issues in these cases and
upholds the current import limit and the allocation of limited import capacity
until the Alturas Intertie is in service. As of December 22, 1998 when the
Alturas Intertie became commercially operational and until February 28, 2001,
Truckee Donner Public Utility District will receive 30 MW of import capability.
After February 28, 2001, allocation of import capacity will be determined by the
FERC based on the results of SPPC's 1998 resource plan and a subsequent filing
with FERC in 1999. On July 9, 1998, the settlement was certified and is pending
FERC approval.
On November 30, 1998, the FERC issued an order accepting the Alturas
Interconnection and O&M agreement between the Company, Bonneville Power
Administration (BPA) and Pacificorp. The order requires SPPC to work with the
WSCC members to establish operating procedures to avoid impacting the
reliability of other systems. On December 22, 1998, SPPC filed the draft
Alturas Operating Agreement between the Company, BPA and Pacificorp.
NOTE 3. JOINTLY-OWNED FACILITIES
Valmy
- -----
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.
The following schedule reflects SPPC's 50% ownership interest in jointly-
owned electric utility plant at December 31, 1998 (dollars in thousands):
<TABLE>
<CAPTION>
Electric Accumulated Construction
<S> <C> <C> <C> <C> <C>
MW Plant Provision For Work In
Plant Capacity In Service Depreciation Progress
------------ ------------ ---------------- ------------------- ------------------
Valmy #1 129 $127,642 $53,152 $469
Valmy #2 137 $153,684 $52,916 $735
</TABLE>
58
<PAGE>
Pinon Pine
- ----------
Pinon Pine Corp. and Pinon Pine Investment Co., subsidiaries of SPPC, own
25% and 75% of a 38% interest in Pinon Pine Company, L.L.C. GPSF-B, a Delaware
corporation formerly owned by General Electric Capital Corporation (GECC) and
now also owned by SPPC, owns the remaining 62% as of February 1999. 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 (S) 29
of the Internal Revenue Code. The entire project, which includes an LLC-owned
gasifier and an SPPC-owned power island and post-gasification facilities to
partially cool and clean the syngas, is referred to collectively as the Pinon
Pine Power Project.
SPPC has a funding arrangement with the Department of Energy (DOE). Under
the agreement, the DOE will provide funding towards the construction of the
project, and towards the operating and maintenance costs of the facility. The
DOE has committed $168 million of funding for Pinon construction and operation
costs. The DOE provided funding for approximately 43% of the estimated
construction cost and half of the operating and fuel expenses and will provide
funding until the commitment is expended. A dispute has arisen with the DOE
regarding the historical and future funding of natural gas costs. In February
1999, the DOE informed the Company it will not fund the remaining $14 million
under the cooperative agreement until the dispute is resolved. Estimated
construction start-up and commissioning costs for Pinon, including the DOE's
portion are approximately $301.5 million, which includes permitting taxes,
start-up commissioning, operator training and Allowance for Funds Used During
Construction. DOE funding for construction through December 1998 is $132.4
million .
Construction began on the project in February 1995, following resource
plan approval and the receipt of all permits and other approvals. The natural
gas portion (combined cycle combustion turbine) was satisfactorily completed and
placed in service December 1, 1996. The balance of the plant was completed
in June 1998. The construction of the gasifier portion of the project
overran the fixed contract price by approximately 12% or $12.6 million. The
overrun is primarily due to redesign issues, resolving technical issues relative
to start up and other costs due to a later than anticipated completion date. To
date, SPPC has not been successful in obtaining sustained operation of the
gasifier but work continues to identify problem areas and redesign solutions
which will likely require additional capital expenditures. Due to the problems
noted above, SPPC and Foster Wheeler settled on a portion of the cost overrun
and have entered into an alternative dispute resolution.
SPPC had to satisfy certain performance requirements as part of the
construction agreement with the LLC. The initial performance warranty required
that the gasifier attain an average capacity factor of 30% during 1997,
regardless of delays in the in-service date. Since the gasifier was not in
service in 1997, the certain performance warranties required by the contract
were not met. Consequently, SPPC paid GECC $2.8 million as satisfaction of the
performance obligation.
59
<PAGE>
NOTE 4. PREFERRED STOCK
All issues of SPPC preferred stock are superior to SPR common stock with
respect to dividend payments (which are cumulative) and liquidation rights.
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.
The following table indicates the number of shares outstanding and the
dollar amount thereof at December 31 of each year. The difference between total
shares authorized and the amount outstanding represents undesignated shares
authorized but not issued.
<TABLE>
<CAPTION>
Shares Issued Amount
--------------------------------------------------- -----------------------------
1998 1997 1996 1998 1997 1996
------------- ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
(dollars in thousands)
Not subject to
mandatory redemption:
Series A 80,500 80,500 80,500 $ 4,025 $ 4,025 $ 4,025
Series B 82,000 82,000 82,000 4,100 4,100 4,100
Series C 299,800 299,800 299,800 14,990 14,990 14,990
Class A Series I 2,000,000 2,000,000 2,000,000 50,000 50,000 50,000
--------- --------- --------- -------- -------- --------
Subtotal 2,462,300 2,462,300 2,462,300 73,115 73,115 73,115
Subject to mandatory
redemption:
Preferred
securities of
Sierra Pacific
Power
Capital I 1,940,000 1,940,000 1,940,000 48,500 48,500 48,500
----------------------------------------- ----------------------------------------
Total 4,402,300 4,402,300 4,202,300 $121,615 $121,615 $121,615
========================================= ========================================
</TABLE>
SPPC redeemed 408,000 shares of Series G, 8.24% Preferred Stock, at par
value, for $20.4 million on June 3, 1996 using the proceeds from the following
issuance of Preferred Securities.
On July 29, 1996, Sierra Pacific Power Capital I (the Trust), a wholly-
owned subsidiary of SPPC, issued $48.5 million (1,940,000 shares) 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 under the guarantee agreement entered into in connection with
the preferred securities, when taken together with the SPPC's obligation to make
interest and other payments on the junior subordinated debentures issued to the
Trust, and SPPC's obligations under its Indenture pursuant to which the junior
subordinated debentures are issued and its obligations under the declaration,
including its liabilities to pay costs, expenses, debts and liabilities of the
Trust, provides a full and unconditional guarantee by SPPC of the Trust's
obligations under the Preferred Securities. In addition to retiring the $20.4
million of Series G Preferred Stock, proceeds were used to reduce short-term
borrowings.
60
<PAGE>
The Preferred Securities of Sierra Pacific Power Capital I are redeemable
only in conjunction with the redemption of the related 8.60% junior subordinated
debentures. The junior subordinated debentures will mature on July 30, 2036,
and may be redeemed, in whole or in part, at any time on or after July 30, 2001,
or at any time in certain circumstances upon the occurrence of a tax event. A
tax event occurs if an opinion has been received from tax counsel that there is
more than an insubstantial risk that: the Trust is, or will be subject to
federal income tax with respect to interest accrued or received on the junior
subordinated debentures; the Trust is, or will be subject to more than a de
minimis amount of other taxes, duties or other governmental charges; interest
payable by SPPC to the Trust on the junior subordinated debentures is not, or
will not be, deductible, in whole or in part for federal income tax purposes.
Upon the redemption of the junior subordinated debentures, payment will
simultaneously be applied to redeem preferred securities having an aggregate
liquidation amount equal to the aggregate principal amount of the Junior
Subordinated Debentures. The preferred securities are redeemable at $25 per
preferred security plus accrued dividends.
NOTE 5. LONG-TERM DEBT
Substantially all utility plant is subject to the lien of the SPPC
indenture under which the first mortgage bonds are issued.
On June 30, 1997, SPPC redeemed $15 million 6.5% First Mortgage Bonds
which had been included in the current liability portion of the consolidated
balance sheet.
On June 17, 1998, SPPC redeemed $ 5 million 8.65% First Mortgage Bonds
before the due date in 2022.
In December 1998, SPPC issued $35 million principal amount of
collateralized Medium-Term Notes, Series D, consisting of three year non-
callable notes, due in 2001, with interest rates of 5.47% and five year non-
callable notes, due in 2003, with interest rates ranging from 5.50% to 5.59%.
For all notes, interest is payable in semi-annual payments. The proceeds to SPPC
from the sale of the notes is to be used for general corporate purposes
including but not limited to: the acquisition of property; the construction,
completion, extension or improvement of facilities; or discharge or refunding of
obligations, including short-term borrowings.
SPPC's aggregate annual amounts of maturities for long-term debt for each
fiscal year ended 1999 through 2003 are shown below (dollars in thousands):
<TABLE>
<S> <C> <C>
1999 $30,500
2000 300
2001 17,200
2002 200
2003 18,200
</TABLE>
61
<PAGE>
NOTE 6. TAXES
The following reflects the composition of taxes on income
(in thousands of dollars):
<TABLE>
<CAPTION>
1998 1997 1996
---------------------------------------------------------------
<S> <C> <C> <C>
Federal:
Taxes estimated to be currently payable $46,176 $40,574 $33,070
Deferred taxes related to:
Excess of tax depreciation over book depreciation 4,100 3,997 5,217
Deferral of energy costs deducted currently for tax
purposes-net - (3) (307)
Contributions in aid of construction and customer advances (2,963) (3,966) (2,917)
Avoided interest capitalized (875) (1,578) (3,124)
Costs of abandoned merger - 301 4,359
Net amortization of investment tax credit (1,930) (1,962) (1,961)
Other-net (2,075) 712 (33)
State (California) 925 801 754
---------------------------------------------------------------
Total $ 43,358 $ 38,876 $ 35,058
===============================================================
As Reflected in Statement of Income:
Federal income taxes $ 42,625 $ 39,586 $ 35,487
State income taxes 925 801 754
---------------------------------------------------------------
Operating Income 43,550 40,387 36,241
Other income-net (192) (1,511) (1,183)
---------------------------------------------------------------
Total $ 43,358 $ 38,876 $ 35,058
===============================================================
</TABLE>
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):
<TABLE>
<CAPTION>
1998 1997 1996
---------------------------------------------------------------
<S> <C> <C> <C>
Income before preferred dividend requirements $ 86,020 $ 83,127 $ 73,651
Total income tax expense 43,358 38,876 35,058
---------------------------------------------------------------
129,378 122,003 108,709
Statutory tax rate 35% 35% 35%
---------------------------------------------------------------
Expected income tax expense 45,282 42,701 38,048
Depreciation related to difference in cost basis for tax purposes 1,383 1,591 2,456
Allowance for funds used during construction-equity (1,334) (1,912) (1,831)
Tax benefit from the disposition of assets 63 (569) (1,130)
ITC amortization (1,930) (1,962) (1,961)
California franchise taxes (net of federal benefit) 601 521 490
Other-net (707) (1,494) (1,014)
---------------------------------------------------------------
$ 43,358 $ 38,876 $ 35,058
===============================================================
Effective tax rate 33.5% 31.9% 32.2%
</TABLE>
62
<PAGE>
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):
<TABLE>
<CAPTION>
1998 1997 1996
-------------------------------------------------------------
<S> <C> <C> <C>
Accumulated Deferred Federal
Income Tax Liabilities:
AFUDC $ 8,378 $ 7,174 $ 5,745
Bond redemption's 5,865 6,423 6,690
Excess of tax depreciation over book depreciation 157,906 154,240 142,441
Repairs and maintenance 6,180 4,355 3,047
Tax benefits flowed through to customers 65,619 66,563 67,667
Other 3,161 1,498 4,485
-------------------------------------------------------------
Total 247,109 240,253 230,075
-------------------------------------------------------------
Accumulated Deferred Federal Income Tax Assets:
Avoided interest capitalized 14,694 13,819 12,241
Employee benefit plans 3,049 1,783 1,132
Contributions in aid of construction and customer advances 33,925 30,697 25,980
Gross-ups received on contributions in aid of construction and
advances 4,512 4,197 3,529
Unamortized investment tax credit 20,432 21,471 22,527
Other 8,800 5,659 2,229
-------------------------------------------------------------
Total 85,415 77,626 67,638
-------------------------------------------------------------
Accumulated Deferred Federal Income Taxes $161,697 $162,627 $162,437
=============================================================
</TABLE>
The Company's balance sheets contain a net regulatory tax asset of $26.7
million at year-end 1998 and $25.8 million at year-end 1997. The net regulatory
asset consists of future revenue to be received from customers (a regulatory tax
asset) of $65.6 million at year-end 1998 and $66.6 million at year-end 1997, 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 tax
liability), consisting of $18.5 million at year-end 1998 and $19.3 million at
year-end 1997, due to temporary differences for liberalized depreciation at
rates in excess of current tax rates, and $20.4 million at year-end 1998 and
$21.5 million at year-end 1997 due to temporary differences caused by the
investment tax credit. The regulatory tax 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 tax liability for temporary differences caused by the investment tax
credit will be amortized ratably in the same fashion as the accumulated deferred
investment credit.
NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The December 31, 1998 carrying amount for cash, cash equivalents, current
assets, accounts payable and current liabilities approximates fair value due to
the short-term nature of these instruments.
63
<PAGE>
The total fair value of SPPC's long-term debt at December 31, 1998, is
estimated to be $641.9 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 $640.4 million as of December 31, 1997.
NOTE 8. SHORT-TERM BORROWINGS
In January of 1998 the Company revised its credit facilities resulting in a
$150 million 364-day credit facility for the Alturas project, and a $50 million
revolving credit facility to support commercial paper activity. The $150
million Alturas credit facility was used primarily to finance the construction
of the Alturas Intertie. This facility expired on January 29, 1999. The
Company utilized $105 million of the facility during 1998. Facility fees for
1998 were approximately $120,000 for the Alturas Credit Facility, and $60,000
for the revolving credit facility. Facility fees for 1997 were approximately
$101,000.
On January 29, 1999 SPPC established a new $150 million unsecured credit
facility for general corporate purposes. This credit facility will expire on
December 31, 1999. SPPC pays the lender a facility fee on the commitment
quarterly, in arrears.
At December 31, 1998, SPPC's short-term debt was $105.0 million drawn from
the Alturas credit facility at an average interest rate of 5.41%. At December
31, 1997, SPPC had a balance of $75 million in short-term borrowings comprised
entirely of commercial paper at an average interest rate of 6.12%.
The other subsidiaries of SPPC have no outstanding short-term borrowings at
this time.
NOTE 9. DIVIDENDS
The Restated Articles of Incorporation of SPPC and the indentures relating
to the various series of its First Mortgage Bonds contain restrictions as to the
payment of dividends on its common stock. Under the most restrictive of these
limitations, approximately $84 million of retained earnings were available at
December 31, 1998 for the payment of common stock cash dividends.
NOTE 10. RETIREMENT PLAN AND POSTRETIREMENT BENEFITS
SPPC sponsors a noncontributory defined benefit retirement plan covering
all employees who satisfy the service requirement and a defined benefit post-
retirement plan that covers administrative employees and those covered under
collective bargaining agreements. The plan provides medical, dental and life
insurance benefits for retirees.
The retirement plan provides benefits based on each covered employee's
years of service, highest five-year average compensation, and a step rate
benefit formula indirectly integrating the plan with Social Security.
64
<PAGE>
Beginning in 1998, retirement plan provisions applicable to employees
covered by the collective bargaining agreement were amended to recognize
additional compensation as pensionable pay and to reduce the penalty for
retirement before age 62.
SPPC's funding policy for the retirement plan is to contribute an
annual amount to an irrevocable trust that is not less than the minimum funding
requirement under the Employee Retirement Income Security Act of 1974, and not
in excess of the amount that can be deducted for federal income tax purposes.
The plan's assets are invested primarily in common stocks, marketable bonds, and
other fixed-income securities. The remainder is held in cash and cash
equivalents. None of the plan assets are invested in SPR common or SPPC
preferred stock.
In April 1995, SPPC offered an early retirement plan to non-bargaining
unit employees age 50 or older with at least 15 years of credited service as of
January 1, 1996 and whose age and credited years of service equaled at least 70.
The present value of termination costs relating to the 112 employees who
accepted the offering was originally recorded in 1995 at $16.8 million, but was
revalued at $12.8 million during 1996 due to a revision in the measurement date.
These termination costs were fully deferred, as a regulatory asset, as of
December 31, 1995. During 1996, SPPC began amortizing the termination costs by
recognizing expense for both 1995 and 1996. SPPC is using a ten-year
amortization period for these costs, consistent with the treatment of previous
early retirement programs.
For management, professional and administrative employees, the post-
retirement plan is contributory for individuals retiring after January 1, 1993,
with retiree contributions tied to each retiree's length of service.
Additionally, the plan requires employees retiring after January 1, 1993 to
participate in Medicare Part "B". Life insurance benefits remain
noncontributory for retirees. However, the amount of life insurance provided
for retirees is significantly less than that provided to active employees.
Also, dental coverage is discontinued for all employees at age 65.
Beginning in 1998, post-retirement plan provisions applicable to
employees covered by the collective bargaining agreement were amended. Retiree
contributions were increased to a minimum of 10% plus an additional amount for
each year of service fewer than 20. Also, the plan introduced a managed care
option for future retirees.
SPPC's funding policy for its post-retirement benefit obligation takes
advantage of federal income tax deductions. Contributions are being made to two
voluntary employee's beneficiary associations and in IRC (S)401(h) account.
Plan assets are invested primarily in common stocks, marketable bonds and other
fixed income securities. The remainder is held in cash and cash equivalents.
None of the plan assets are invested in SPR common or SPPC preferred stock.
Post-retirement health care costs for key executives continue to be paid from
SPPC's general assets.
65
<PAGE>
The following table sets forth a reconciliation of the funded status
of the plans with amounts included in SPPC's consolidated balance sheets for
1998, 1997 and 1996 (dollars in thousands).
<TABLE>
<CAPTION>
Pension Benefits Post-Retirement Benefits
1998 1997 1996 1998 1997 1996
-------------- ------------- -------------- --------------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at beginning
Of year $186,612 $157,660 $165,877 $ 65,483 $ 73,526 $ 73,821
Service cost 7,047 5,825 6,652 2,162 2,440 2,587
Interest cost 13,702 11,920 11,778 4,817 5,597 5,269
Plan participant's
contributions - - - 67 54 41
Amendments - 5,204 - - (3,520) 415
Actuarial gain 8,310 14,500 (18,540) 6,661 (10,278) (6,277)
Benefits paid (8,563) (8,497) (8,107) (2,764) (2,336) (2,330)
-------------- ------------- -------------- --------------- ----------- ----------
Benefit obligation at end of year 207,108 186,612 157,660 76,426 65,483 73,526
-------------- ------------- -------------- --------------- ----------- ----------
Change in plan assets
Fair value of plan assets at
Beginning of year 190,535 167,416 148,300 39,326 32,944 24,620
Actual return on plan assets 23,160 32,534 19,954 7,069 5,202 1,942
Employer contribution - - 8,087 4,143 3,668 8,877
Plan participant's
contributions - - - 67 54 41
Expenses paid (1,275) (917) (818) (252) (206) (206)
Benefits paid (8,563) (8,498) (8,107) (2,764) (2,336) (2,330)
Fair value of plan assets at end -------------- ------------- -------------- --------------- ----------- ----------
of year 203,857 190,535 167,416 47,589 39,326 32,944
-------------- ------------- -------------- --------------- ----------- ----------
Funded status 3,251 (3,923) (9,756) 28,837 26,157 40,582
Unrecognized net actuarial gain 26,519 29,352 26,661 16,716 20,837 8,562
Unrecognized prior service cost (8,404) (9,083) (4,251) - - (415)
Unrecognized transition obligation - - - (31,563) (33,818) (39,419)
-------------- ------------- -------------- --------------- ----------- ----------
Accrued benefit cost $ 21,366 $ 16,346 $ 12,654 $ 13,990 $ 13,176 $ 9,310
============== ============= ============== =============== ===========================
</TABLE>
In the preceding table, unrecognized net gain represents the net gain
attributable to changes in actuarial assumptions and differences between actual
experience and actuarial assumptions. Also, service cost represents the
benefits earned during the year while interest cost represents the increase in
the accumulated benefit obligation due to the passage of time.
<TABLE>
<CAPTION>
Pension Benefits Post-Retirement Benefits
1998 1997 1996 1998 1997 1996
------------ ------------- ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
Weighted-average assumptions
as of December 31
Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 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% 5.00% 5.00% 4.50% 5.00% 5.00%
</TABLE>
66
<PAGE>
For 1996, the Company used a graduated medical trend rate assumption
with an initial rate of 11.25%. This medical trend rate declined by 0.50% over
the next ten years to an ultimate rate of 5.75% in 2007, remaining at the level
thereafter. Beginning in 1997, the obligation valuation changes to a flat trend
rate of 6.00% for each year as well as the adoption of the 1994 Group Annuity
Generational Mortality Table.
<TABLE>
<CAPTION>
($000) Pension Benefits Post-Retirement Benefits
1998 1997 1996 1998 1997 1996
----------- ---------- ----------- --------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Components of net periodic
benefit cost
Service cost $ 7,047 $ 5,825 $ 6,652 $ 2,162 $ 2,440 $ 2,587
Interest cost 13,702 11,920 11,778 4,817 5,597 5,269
Expected return on plan assets (15,800) (13,844) (12,590) (3,495) (2,937) (2,036)
Amortization of prior service cost 679 372 372 33 -
Amortization of transition obligation - - 2,255 2,464 2,464
Recognized net actuarial gain (609) (581) - (783) (62)
----------- ---------- ----------- --------- ---------- ----------
Net periodic benefit cost:
SFAS No. 132 5,019 3,692 6,212 4,956 7,535 8,284
Amount expensed :
SFAS No. 71 - Net 2,599 2,599 3,882 805 805 2,044
----------- ---------- ----------- --------- ---------- ----------
Total net periodic benefit cost $ 7,618 $ 6,291 $ 10,094 $ 5,761 $ 8,340 $10,328
=========== ========== =========== ========= ========== ==========
</TABLE>
The amount expensed under SFAS No. 71 for the retirement plan
represents the SFAS No. 88 costs arising from the 1989, 1992 and 1995 early
retirement programs. Pursuant to PUCN directive and prior precedent, costs for
the 1989, 1992, and 1995 programs are being amortized over 10 years.
Assumed health care cost trend rates have a significant effect on the
amounts reported for post-retirement plans. A one-percentage-point change in the
assumed health care cost trend would have the following effects:
<TABLE>
<CAPTION>
1-Percentage- 1-Percentage-
Point Increase Point Decrease
<S> <C> <C>
Effect on total of service and interest
cost components $ 1.8 million $(1.4 million)
Effect on post-retirement
Benefit obligation $14.0 million $(11.0 million)
</TABLE>
In addition to the employee retirement plan covering all employees,
SPPC has a Supplemental Executive Retirement Plan which is a non-qualified
defined benefit plan under which SPPC will pay out of general assets
supplemental pension benefits to key executives. SPPC also has a non-qualified
supplemental pension plan covering certain employees. This plan provides for
incremental pension payments from SPPC's funds so that total pension payments
equal amounts that would have been payable from SPPC's principal pension plan if
it were not for limitations imposed by income tax regulations. The unfunded
liability under these plans as of
67
<PAGE>
December 31, 1998, 1997 and 1996 was $5.6 million, $5.2 million and $4.9
million, respectively.
NOTE 11. STOCK COMPENSATION PLANS
At December 31, 1998 the Company had several stock-based compensation plans
which are described below. The Company applies Accounting Principals Board
Opinion No. 25 and related Interpretations in accounting for its plans.
Accordingly, no compensation cost has been recognized for nonqualified stock
options and the employee stock purchase plan. The total compensation cost that
has been charged against income for the performance shares, dividend equivalents
and the non-employee director stock plans was $.5 million, $1.4 million and $.9
million for 1998, 1997 and 1996, respectively. Had compensation cost for the
Company'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 method of Statement of Financial Accounting Standard
No. 123, the Company's income applicable to common stock would have been
decreased to the pro forma amounts indicated below:
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------ -------------
<S> <C> <C> <C> <C>
Income applicable to
common stock As Reported $80,561 $77,668 $67,351
Pro Forma $80,217 $77,500 $67,284
</TABLE>
The Company'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 the Company's common shares to key employees
through December 31, 2003. 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 1998, 1997 and 1996, the Company issued only
nonqualified stock options and performance shares under the plan.
Nonqualified stock options granted during 1998, 1997 and 1996 were granted
at an option price not less than market value at the date of the grant (January
1, 1998, January 1, 1997 and January 1, 1996, respectively). The 1998 and 1997
options vest to the participants 33 1/3% per year over a three year period from
the grant date and may be exercised for a period not exceeding ten years from
the date of the grant. The 1996 options vest to the participants 20% per year
over a five year period from the grant date and may be exercised for a period
not exceeding ten years from the date of the grant. The options may be
exercised using either cash or previously acquired shares, valued at the current
market price, or a combination of both.
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 in 1998, 1997 and 1996, respectively: dividend yield
of 4.71%, 5.30% and 5.50%; expected volatility of 13.16%, 11.42% and 11.57%;
risk-free rates of return of 5.81%, 6.68% and 5.75%; and an expected life of 10
years for all grants.
68
<PAGE>
A summary of the status of the Company's nonqualified stock option plan as
of December 31, 1998, 1997 and 1996, and changes during those years is presented
below:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
Weighted Weighted Weighted
-Average -Average -Average
Shares Exercise Shares Exercise Shares Exercise
Nonqualified Stock Options (000) Price (000) Price (000) Price
------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 158 $25.51 89 $20.73 70 $19.59
Granted 125 $35.90 98 $28.75 28 $23.38
Exercised (31) $24.24 (15) $20.28 (1) $19.83
Forfeited (44) $27.12 (14) $23.17 (8) $20.04
Outstanding at end of year 208 $31.62 158 $25.51 89 $20.73
Options exercisable at year-end 38 $24.54 25 $20.32 18 $19.83
Weighted-average fair value of
options granted during the year $4.79 $3.51 $2.13
</TABLE>
The following table summarizes information about nonqualified stock options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------- -------------------------------
Number Remaining Number
Exercise Outstanding at Contractual Exercise Exercisable at
Price 12/31/98 Life Price 12/31/98
----------------------------------------------- -------------------------------
<S> <C> <C> <C> <C>
$20.500 9,088 5 years $20.500 7,270
$18.750 12,544 6 years $18.750 7,526
$23.375 11,180 7 years $23.375 4,472
$28.750 55,598 8 years $28.750 18,570
$35.900 120,000 9 years $35.900 -
</TABLE>
During 1998, 1997 and 1996, the Company granted performance shares in the
following numbers and initial values, respectively: 12,700, 14,090 and 8,973
shares; and $35.90, $28.75 and $23.375 per share. The actual number of shares
earned is dependent upon SPR achieving certain financial goals over three-year
performance periods. The value of performance shares, if earned, will be equal
to the market value of SPR's common shares as of the end of the performance
periods. The Company, at its sole discretion, may pay earned performance shares
in the form of cash or in shares (or a combination thereof).
Simultaneous with the grant of both the nonqualified options and
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
from the date of grant through the exercise date, or, in the case of performance
shares, 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.
69
<PAGE>
Under the Company's employee stock purchase plan, SPR is authorized to
issue up to 400,162 shares of common stock to all of its employees with minimum
service requirements. Under the terms of the plan, employees can choose twice
each year to have up to 15% of their base earnings withheld to purchase the
Company'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 15,282, 17,822 and
15,602 shares to employees in 1998, 1997 and 1996, 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 1998, 1997 and 1996, respectively: average dividend yield of 4.17%, 4.87%
and 5.38%; average expected volatility of 14.16%, 11.57% and 11.51%; and average
risk-free interest rates of 4.96%, 5.59% and 5.45%. The weighted average fair
value of those purchase rights in 1998, 1997 and 1996 was $4.94, $4.14 and
$3.26, respectively.
The Company's non-employee director stock plan provides that a portion of
the outside directors' annual retainer be paid in Company stock. Effective May
20, 1996, the annual retainer for non-employee directors was increased from
$14,000 to $30,000. The minimum amount to be paid in Company stock was also
increased from $4,000 to $20,000 per director, over the prior year. During 1998,
1997 and 1996, the Company granted the following total shares and related
compensation to directors in Company stock, respectively: 6,391, 8,208 and 9,212
shares; and $233,250, $230,833 and $160,417.
NOTE 12. POSTEMPLOYMENT BENEFITS
During 1995, SPPC offered a severance program to non-bargaining-unit
employees which provided both severance pay and medical benefits continuation
totaling $7.0 million and $0.5 million, respectively. These costs were deferred
as a regulatory asset as of December 31, 1995. SPPC began amortization of these
costs during 1996 over a ten-year period consistent with the period used for
pension and post-retirement benefits. There was no remaining liability for
unpaid severance and benefits at December 31, 1998, 1997 or 1996.
NOTE 13. COMMITMENTS AND CONTINGENCIES
SPPC's estimated cash construction expenditures for the year 1999 and the
five-year period 1999-2003 are $112.7 million and $639.8 million, respectively.
70
<PAGE>
Several of SPPC's purchased power, gas supply and pipeline capacity, and
coal supply contracts contain minimum volume provisions, which SPPC is either
meeting or exceeding. SPPC anticipates continuing to meet or exceed them in the
future. Estimated future commitments under non-cancelable agreements with
initial terms of one year or more at December 31, 1998 were as follows (in
thousands of dollars):
<TABLE>
<S> <C>
1999 $170,700
2000 148,900
2001 104,900
2002 83,800
2003 82,300
After 2003 to 2015 425,800
</TABLE>
SPPC has an operating lease for its corporate headquarters building, a
334,000 square foot, five-floor, multi-purpose building located in southeast
Reno, Nevada. 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. SPPC subleases building space to various tenants. These subleases vary
from year to year and are shown at net of total lease.
The total rental expense under all leases (net) was approximately $7.5
million in 1998, $7.4 million in 1997 and $8.2 million in 1996.
Estimated future minimum lease commitments (net of the corporate
headquarters building subleases described above) under non-cancelable operating
leases with initial terms of one year or more at December 31, 1998 were as
follows (in thousands of dollars):
<TABLE>
<S> <C>
1999 $ 8,700
2000 6,600
2001 6,300
2002 6,200
2003 7,000
After 2003 to 2018 41,800
-------
Total $76,600
=======
</TABLE>
SPPC has no material capital lease commitments.
See Notes 1, 5, 7, and 10 of SPPC's consolidated financial statements for
additional commitments and contingencies.
SPPC, through the course of its normal business operations, is currently
involved in a number of 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.
71
<PAGE>
NOTE 14. SEGMENT INFORMATION
The Company adopted FASB statement No. 131, Disclosure about Segments of an
Enterprise and Related Information, for its annual reports as of December 31,
1998. The Company operates three business segments providing regulated
electric, natural gas and water service. Electric service is provided to
northern Nevada and the Lake Tahoe area of California. Natural gas and water
services are provided in the Reno-Sparks area of Nevada.
Information as to the operations of the different business segments is set
forth below based on the nature of products and services offered. The Company
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 the summary of significant
accounting policies (Note 1). Intersegment revenues are not material.
Financial data for business segments is as follows (in thousands).
<TABLE>
<CAPTION>
Reconciling
December 31, 1998 Electric Gas Water Eliminations Consolidated
- --------------------- ----------- ----------- ----------- ------------ ---------------
<S> <C> <C> <C> <C> <C>
Operating Revenues $ 585,657 $ 99,532 $ 49,143 $ 734,332
------------ ----------- =========== ============ ===============
Operating income $ 103,728 $ 10,534 $ 11,932 $ 126,194
============ =========== =========== ============ ===============
Operating income taxes $ 34,611 $ 5,142 $ 3,797 $ 43,550
============ =========== =========== ============ ===============
Depreciation and Amortization $ 57,180 $ 4,810 $ 7,445 $ 69,435
============ =========== =========== ============= ===============
Interest expense on long term debt $ 28,277 $ 4,001 $ 10,911 $(4,299) $ 38,890
============ =========== =========== ============ ===============
Assets $1,558,322 $139,398 $274,124 $39,976 $2,011,820
============ =========== =========== ============ ===============
Capital expenditures $ 144,080 $ 11,124 $ 28,180 $ 183,384
============ =========== =========== ============ ===============
<CAPTION>
Reconciling
December 31, 1997 Electric Gas Water Eliminations Consolidated
- --------------------- ------------ ----------- ----------- ------------ ---------------
Operating revenues $ 540,346 $ 70,675 $ 46,519 $ 657,540
============ =========== =========== ============ ===============
Operating income $ 99,671 $ 10,057 $ 10,444 $ 120,172
============ =========== =========== ============ ===============
Operating income taxes $ 33,742 $ 4,223 $ 2,422 $ 40,387
============ =========== =========== ============ ===============
Depreciation and amortization $ 52,239 $ 4,531 $ 7,347 $ 64,117
============ =========== =========== ============ ===============
Interest expense on long term debt $ 31,098 $ 3,653 $ 9,158 $(4,300) $ 39,609
============ =========== =========== ============ ===============
Assets $1,463,969 $130,392 $282,524 $35,357 $1,912,242
============ =========== =========== ============ ===============
Capital expenditures $ 105,531 $ 12,191 $ 30,079 $ 147,801
============ =========== =========== ============ ===============
<CAPTION>
Reconciling
December 31, 1996 Electric Gas Water Eliminations Consolidated
- --------------------- ------------ ----------- ----------- ------------ ---------------
Operating revenues $ 507,004 $ 67,376 $ 45,344 $ 619,724
============ =========== ============ ============ ===============
Operating income $ 86,428 $ 11,035 $ 9,545 $ 107,008
============ =========== ============ ============ ===============
Operating income taxes $ 27,743 $ 4,872 $ 3,626 $ 36,241
============ =========== ============ ============ ===============
Depreciation and amortization $ 47,797 $ 4,223 $ 6,098 $ 58,118
============ =========== ============ ============ ===============
Interest expense on long term debt $ 27,856 $ 3,480 $ 7,519 $(1,804) $ 37,051
============ =========== ============ ============ ===============
Assets $1,407,927 $122,137 $276,954 $35,610 $1,842,628
============ =========== ============ ============ ===============
Capital expenditures $ 158,482 $ 10,798 $ 33,829 $ 203,109
============ =========== ============ ============ ===============
</TABLE>
72
<PAGE>
The reconciliation of segment information to consolidated totals in the
preceding table includes an adjustment for intersegment interest expense
eliminated from the consolidated totals. The reconciliation of segment assets
to the consolidated total includes the following unallocated amounts.
<TABLE>
<CAPTION>
1998 1997 1996
-------- ------- -------
<S> <C> <C> <C>
Other property $ 1,342 $ 1,928 $ 1,043
Cash 15,197 6,920 890
Current assets-other 2,692 2,572 3,948
Other regulatory assets 21,031 23,876 29,426
Deferred charges-other (286) 61 303
-------- ------- -------
$39,976 $35,357 $35,610
======== ======= =======
</TABLE>
NOTE 15. QUARTERLY FINANCIAL DATA (unaudited)
The following represents unaudited quarterly financial data (dollars in
thousands):
<TABLE>
<CAPTION>
Quarter Ended
-------------
March 31, June 30, Sept. 30, Dec. 31,
1998 1998 1998 1998
------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues $182,722 $169,143 $187,446 $195,021
======== ======== ======== ========
Operating Income $ 33,138 $ 27,308 $ 33,626 $ 32,122
======== ======== ======== ========
Income Before Preferred
Dividend Requirement $ 23,194 $ 17,705 $ 23,751 $ 21,370
======== ======== ======== ========
Income Applicable to
Common Stock $ 21,829 $ 16,340 $ 22,386 $ 20,006
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Quarter Ended
-------------
March 31, June 30, Sept. 30, Dec. 31,
1997 1997 1997 1997
-------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues $171,858 $154,817 $159,783 $171,082
======== ======== ======== ========
Operating Income $ 32,292 $ 26,637 $ 29,194 $ 32,049
======== ======== ======== ========
Income Before Preferred ======== ======== ======== ========
Dividend Requirement $ 23,357 $ 17,337 $ 20,142 $ 22,291
======== ======== ======== ========
Income Applicable to
Common Stock $ 21,992 $ 15,972 $ 18,777 $ 20,927
======== ======== ======== ========
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
73
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
(a) Directors
The following is a listing of all the current directors of SPPC and their
ages as of December 31, 1998. There are no family relationships among them.
Directors serve one-year terms ending at the next annual meeting or until a
successor has been elected and qualified.
Edward P. Bliss, 66
Consultant to Scudder Kemper 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 Director of SPPC since 1992 and of SPR since 1991.
Krestine M. Corbin, 61
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 Bank Twelfth District Head Board. Ms. Corbin
has served as a Director of SPPC since 1992 and of SPR since 1989.
Theodore J. Day, 49
Senior Partner, Hale, Day, Gallagher Company, a real estate brokerage
and investment firm. Mr. Day has served as a Director of SPPC since 1986
and of SPR since 1987. He is also a Director of the W.M. Keck Foundation.
Harold P. Dayton, Jr., 76
Retired President of Dayton's Furniture, Inc. Mr. Dayton has served as
a Director of SPPC since 1967 and of SPR since 1983.
James R. Donnelley, 63
Vice Chairman of the Board, R.R. Donnelley & Sons Company, since July
1990. He was Group President, Corporate Development from June 1987 to July
1990 and Group President, Financial Printing Services Group from January
1985 to January 1988 for R.R. Donnelley and Sons Company. He has been a
Director of that Company since 1976. He is also a Director of Pacific
Magazines & Printing Limited and Director and Chairman of National Merit
Scholarship Corporation. Mr. Donnelley has served as a Director of SPPC
since 1992 and of SPR since 1987.
74
<PAGE>
Richard N. Fulstone, 71
President and General Manager of R.N. Fulstone Company since 1957 and
President and General Manager, F.M. Fulstone, Inc., since 1982. Both
companies engage in farming, cattle ranching and investments. Mr. Fulstone
has served as a Director of SPPC since 1992 and of SPR since 1986.
Malyn K. Malquist, 46, Chairman, President and Chief Executive Officer
Mr. Malquist was elected President and Chief Executive Officer of the
Company and SPR on January 14, 1998. On February 24, 1998, Mr. Malquist
was elected to the additional position of Chairman for both the Company and
SPR. He was Sr. Vice President - Distribution Services Business Group and
Principal Operations Officer from August 1996 to January 1998. He served
as Senior Vice President and Chief Financial Officer of the Company and SPR
when he joined the Company in April 1994 to August 1996. Prior to joining
the Company, he was with San Diego Gas and Electric, where since 1978 he
held various financial positions, including Treasurer in 1990 and Vice
President in 1993.
James L. Murphy, 69
Certified Public Accountant and retired partner of and consultant to
Grant Thornton L.L.P., an international accounting and management
consulting firm. He 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 and of SPR since 1992.
Ronald K. Remington, 57
President, Great Basin College since June 1989. He was previously Vice
President of Instruction at Truckee Meadows Community College. Dr.
Remington received his Ph.D. in psychology from the University of Nevada,
Reno. Dr. Remington has served as a Director of SPPC since December 1991.
Dennis E. Wheeler, 56
Chairman, President and Chief Executive Officer of Coeur d'Alene Mines
Corporation since 1986. Mr. Wheeler has served as a Director of SPPC since
1992 and of SPR since 1990.
Robert B. Whittington, 71
Retired newspaper executive; former President, Gannett West Newspaper
Group; Director, Gannett Company, Inc.; and former publisher, Reno Gazette
and Nevada State Journal. Mr. Whittington has served as a Director of both
SPPC and SPR since 1985.
75
<PAGE>
All of the present Directors, with the exception of Dr. Remington, are
Directors of SPR. Messrs. Malquist and Murphy are Directors of Lands of Sierra,
Inc.; Messrs. Dayton and Malquist are Directors of Sierra Gas Holdings Co.;
Messrs. Fulstone and Malquist are Directors of Sierra Water Development Co.;
Messrs. Day and Malquist are Directors of Tuscarora Gas Pipeline Co.; Mr.
Malquist is a Director of Sierra Pacific Resources Media Group, GPSF-B, Pinon
Pine Corp., and Pinon Pine Investment Co. All of the above listed companies
are affiliates of SPPC with the exception of GPSF-B, Pinon Pine Corp., and Pinon
Pine Investment Co which are subsidiaries.
(b) Executive Officers
The following are current executive officers and their ages as of December
31, 1998. There are no family relationships among them. Officers serve a term
which extends to and expires at the meeting of the Board of Directors in May of
each year or until a successor has been elected and qualified.
Malyn K. Malquist, 46, President and Chief Executive Officer
See description under Item 10(a), "Directors", page 75.
William E. Peterson, 51, Senior Vice President, General Counsel and Corporate
Secretary
Mr. Peterson was elected to his present position in January 1994, and
holds the same position with the Company's parent, SPR. He was previously
Senior Vice President, Corporate Counsel from July 1993 to January 1994.
Prior to joining the Company in 1993, he served as General Counsel and
Resident Agent for SPR since 1992, and as a partner in the Woodburn and
Wedge Law Firm since 1982.
Mark A. Ruelle, 37, Senior Vice President, Chief Financial Officer and Treasurer
Mr. Ruelle was elected to his present position March 1, 1997 and holds
the same position with the Company's parent, SPR. Prior to joining the
Company, Mr. Ruelle was President of Westar Energy, a subsidiary of Western
Resources, Inc. 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.
Gerald W. Canning, 50, Vice President, Restructuring Group
Mr. Canning was appointed to his current position in January, 1998.
Prior to this, since November, 1996, he served as Vice President, Power
Production and Fuels. He also served as President of Tuscarora Gas
Pipeline Company, an affiliate of the Company, from 1995 to 1996. Mr.
Canning has been with the Company since 1968, and served in the positions
of Vice President - Electric Production and Fuels Business; Vice President
and General Manager - Wholesale Energy Business; Vice President - Wholesale
Electric Business; Vice President - Electric Operations; and Vice President
- Electric Resources.
76
<PAGE>
Jeffrey C. Ceccarelli, 44, Vice President -- Distribution Services
Mr. Ceccarelli was elected to his current position 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 the Company
since 1972 and has held numerous management positions in operations,
customer service, design and engineering.
Randy Harris, 45, Vice President, Energy Marketing Services Business Group
Mr. Harris was elected to his current position in November 1996. His
prior management positions include: General Manager, Transmission Services
Business Group; Director of Wholesale Business; Director of Operations,
Tuscarora Gas Pipeline; and Manager, Electric Operations. Mr. Harris joined
the Company in 1974.
Steven C. Oldham, 48, Vice President - Transmission Business Group and Strategic
Development
Mr. Oldham was elected to his current position in November 1996. His
previous executive positions include Vice President - 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 the Company since 1976.
Mary O. Simmons, 43, Controller
Ms. Simmons was elected to her current position in June 1997. Her
previous positions include: Director, Water Policy and Planning; Director,
Budgets and Financial Services; and Assistant Treasurer, Shareholder
Relations for SPR. Ms. Simmons, a certified public accountant, has been
with the Company since 1985.
Mary Jane Willier, 52, Vice President, Human Resources
Ms. Willier was elected to her present position in January 1997. She
was previously Vice President, Human Resources Network Group for Bell
Atlantic Corporation. Ms. Willier 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.
Although all outstanding shares of the Company'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 four series of non-voting preferred stock still outstanding and
registered under the Securities Exchange Act of 1934 ("the Act"). As a technical
matter, the Company 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. The Company's officers, all of
whom are currently reporting pursuant to Section 16(a) of the Act with respect
to SPR's common stock, have now filed reports
77
<PAGE>
with respect to the Company's preferred stock, which reports show no past or
current beneficial ownership of such preferred stock.
78
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth information about the compensation of each
Chief Executive Officer that served in that position during 1998, and each of
the four most highly compensated officers for services in all capacities to the
Company and its subsidiaries.
<TABLE>
<CAPTION>
Long-Term Compensation
---------------------------------------
Annual Compensation Awards Payouts
---------------------------------------------------------------------------------
Other Securities
Annual Restricted Underlying
Name and Compen- Stock Options/ LTIP All Other
Principal Salary Bonus sation Awards SARS Payouts Compensation
Position Year ($) ($) ($) ($) (#) ($) ($)
(a) (b) (c) (d) (2) (e) (3) (f) (g) (h) (4) (i) (5)
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Walter M. Higgins (1) 1998 $ 63,234 $ 0 $ 0 $ 0 0 $ 0 $ 703
Chairman, President and 1997 $361,497 $ 0 $ 6,020 $ 0 30,000 $ 0 $47,175
Chief Executive Officer 1996 $334,231 $219,869 $ 0 $ 0 9,594 $181,193 $35,054
Malyn K. Malquist (1) 1998 $292,960 $180,900 $16,486 $ 0 61,000 $ 85,184 $15,805
Chairman, President and 1997 $212,803 $ 92,198 $ 2,052 $ 0 14,000 $101,192 $15,279
Chief Executive Officer 1996 $194,077 $ 95,335 $ 0 $ 0 3,504 $ 51,770 $ 9,380
William E. Peterson 1998 $199,385 $ 71,503 $18,918 $ 0 9,000 $ 85,184 $29,939
Senior Vice President 1997 $207,757 $ 78,184 $17,142 $ 0 10,000 $101,192 $29,488
General Counsel and 1996 $191,923 $ 85,445 $ 3,417 $ 0 3,504 $ 70,508 $20,982
Corporate Secretary
Mark A. Ruelle 1998 $192,116 $ 72,843 $12,342 $ 0 9,000 $ 50,108 $ 8,974
Senior Vice President 1997 $143,308 $ 65,269 $ 3,808 $ 0 8,384 $ 0 $77,329
Chief Financial Officer 1996 $ 0 $ 0 $ 0 $ 0 0 $ 0 $ 0
Treasurer
Mary Jane L. Willier 1998 $159,923 $ 51,975 $10,950 $ 0 5,500 $ 26,868 $ 6,122
Vice President, Human 1997 $135,577 $ 46,027 $ 3,606 $ 0 6,000 $ 0 $72,377
Resources, Sierra 1996 $ 0 $ 0 $ 0 $ 0 0 $ 0 $ 0
Pacific Power Company
Randy G. Harris 1998 $155,769 $ 56,454 $10,788 $ 0 5,500 $ 29,063 $ 5,893
Vice President, Energy 1997 $135,328 $ 45,916 $ 2,657 $ 0 6,000 $ 0 $ 4,672
Marketing Services 1996 $100,731 $ 22,424 $ 5,647 $ 0 0 $ 0 $ 4,112
Business Group
Sierra Pacific Power
Company
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
79
<PAGE>
Notes:
(1) Mr. Higgins resigned from his position of Chairman, President and Chief
Executive Officer on January 14, 1998. Mr. Malquist was named Chairman,
President and Chief Executive Officer on January 15, 1998.
(2) Amounts represent incentive pay received pursuant to SPR's "pay for
performance" team incentive plan approved by stockholders in May, 1994.
(3) No perquisites in the aggregate exceeded the lesser of $50,000 or 10% of
salary and bonus for any named executive. Accordingly, no amount
perquisites have been reported.
(4) Long-term incentive payout relates to performance share payout for the
three-year period January 1, 1996 to December 31, 1998.
(5) Amounts for All Other Compensation include the following for 1998:
. Company contributions under the 401(k) deferred compensation plan for
all administrative employees, executive officers and directors, pursuant
to which the Company matches 50% of each executive officer's deferral up
to 6% of salary. In 1998, the Company matching amount was $4,800 each
for Messrs. Malquist, Peterson, Ruelle, and Harris and Ms. Willier.
. Company contributions to its nonqualified deferred compensation plan for
Messrs. Malquist and Peterson and Ms. Willier were $9,312, $23,157 and
9,016. The additional income on earnings contributed by Messrs. Higgins,
Malquist, Peterson and Ms. Willier which was in excess of 120% of the
federal rate were $481, $121, $301 and $117.
. Imputed income on group term life insurance premiums paid by the Company
for Messrs. Higgins, Malquist, Peterson, Ruelle and Harris and Ms.
Willier was $222, $707, $855, $186, $365 and $628.
. Insurance premiums paid for executive term life policies for Messrs.
Malquist, Peterson, Ruelle and Harris and Ms. Willier were $865, $826,
$271, $728 and $694.
. Mr. Ruelle received a payment of $3,717 from the Company for moving
expenses
80
<PAGE>
OPTIONS/SAR GRANTS IN LAST FISCAL YEAR
The following table shows all grants of options to the named executive
officers of SPPC in 1998. Pursuant to Securities and Exchange Commission (SEC)
rules, the table also shows the present value of the grant at the date of grant.
The exercise price of all options is the market value of the stock as listed on
the New York Stock Exchange at the time the options are granted.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Individual Grants (1)
- -------------------------------------------------------------------------------------------------------------
Percent of
Total
Number of Option/SARS
Securities Granted to Exercise
Underlying Employees of Base
Options/SARS in Fiscal Price Expiration Grant Date
Name Granted Year ($/sh) Date Present Value
(a) (b) (c) (d) (e) (f) (2)
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Walter M. Higgins 0 0.0% $35.90 1/1/08 $ 0
Malyn K. Malquist 61,000 48.6% $35.90 1/1/08 $275,110
William E. Peterson 9,000 7.2% $35.90 1/1/08 $ 40,590
Mark A. Ruelle 9,000 7.2% $35.90 1/1/08 $ 40,590
Mary Jane L. Willier 5,500 4.4% $35.90 1/1/08 $ 24,805
Randy G. Harris 5,500 4.4% $35.90 1/1/08 $ 24,805
- -------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Under the executive long-term incentive plan, the grants of nonqualifying
stock options were made on January 1, 1998. One third of these grants vest
annually commencing one year after the date of the grant.
(2) 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 value listed above include the
stock's expected volatility (13.2%), risk free rate of return (5.81%),
projected dividend yield (4.7%), the stock option term (10 years), and an
adjustment for risk of forfeiture during the vesting period (3 years at
3%). No adjustment was made for non-transferability.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FY-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, 1998.
81
<PAGE>
<TABLE>
<CAPTION>
Number of Securities Value of Unexercised
Underlying Unexercised in-the-Money
Options/SARS at Fiscal Options/SARS at Fiscal
Shares Year-End Year-End
Acquired on Value Exercisable/ Exercisable/
Name Exercise Realized Unexercisable Unexercisable
(a) (b) (c) (d) (e)
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Walter M. Higgins 16,402 $161,942 0 / 0 $ 0 / $ 0
Malyn K. Malquist 0 $ 0 12,915 / 72,581 $187,390 / $251,220
William E. Peterson 0 $ 0 12,579 / 17,914 $192,504 / $117,354
Mark A. Ruelle 0 $ 0 2,795 / 14,589 $ 25,851 / $ 70,601
Mary Jane L. Willier 0 $ 0 2,000 / 9,500 $ 18,500 / $ 48,550
Randy G. Harris 0 $ 0 2,000 / 9,500 $ 18,500 / $ 48,550
- ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(e) Pre-tax gain. Value of in-the-money options based on December 31, 1998
closing trading price of $38.00 less the option exercise price.
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 SPPC. Goals are established for total shareholder return (TSR)
compared against the Dow Jones Utility Index and annual growth in earnings per
share (EPS).
82
<PAGE>
The following table provides information as to the performance shares
granted to the named executive officers of Sierra Pacific Power Company in 1998.
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."
<TABLE>
<CAPTION>
Estimated Future Payouts Under Non-Stock Price-
Based Plans
---------------------------------------------------
Number of Performance
Shares, Units or Other Period
or Other Until Maturation
Name Rights or Payout Threshold $ Target $ Maximum $
(a) (b) (c) (d) (1) (e) (2) (f) (3)
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Walter M. Higgins 0 3 years $ 0 $ 0 $ 0
Malyn K. Malquist 4,500 3 years $80,775 $161,550 $282,713
William E. Peterson 1,300 3 years $23,335 $ 46,670 $ 81,673
Mark A. Ruelle 1,300 3 years $23,335 $ 46,670 $ 81,673
Mary Jane L. Willier 800 3 years $14,360 $ 28,720 $ 50,260
Randy G. Harris 800 3 years $14,360 $ 28,720 $ 50,260
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) The threshold represents the level of TSR and EPS achieved during the cycle
which represents minimum acceptable performance and which, is 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.
83
<PAGE>
PENSIONS PLANS
The following table shows annual benefits payable on retirement at normal
retirement age 65 to elected officers under the Company's defined benefit plans
based on various levels of remuneration and years of service which may exist at
the time of retirement.
<TABLE>
<CAPTION>
Annual Benefits for Years of Service Indicated
Highest Average Five- --------------------------------------------------------------------------------
Years Remuneration 15 Years 20 Years 25 Years 30 Years 35 Years
- ------------------------ --------------------------------------------------------------------------------
<C> <S> <C> <C> <C> <C> <C>
$ 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
</TABLE>
The Company's noncontributory 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 under "Salary" and "Incentive Pay" in
the "Summary Compensation Table. Pension costs of the retirement plan to which
the Company 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 Company has entered into an arrangement with Mr. Peterson crediting him
with four years of service for prior years of service with his previous
employer, most of which was dedicated to performing legal services for SPR and
SPPC, and an additional one-half year credit for each year of service with the
Company for the first ten years of his employment. Years of credited service
for Messrs. Malquist, Peterson, Ruelle and Harris and Ms. Willier are 4.6, 10.8,
.8, 23.6 and .9, respectively.
A supplemental executive retirement plan (SERP) and an excess 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 excess plan is intended to provide benefits
to executive officers whose pension benefits under the Company's retirement plan
are limited by law to certain maximum amounts.
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
84
<PAGE>
years after a change in control of the Company, there is a termination of
employment by the Company 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 the Company'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 the Company is not the surviving corporation,
the sale of all or substantially all the assets of the company (not the sale of
a work unit) or the acquisition by any person or entity of 30% or more of the
voting power of the Company.
In addition, several merger-related and merger-conditioned severance
arrangements have been entered into between the Company and several executives,
which are described in the section titled Certain Relationships and Related
Transactions.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Voting Stock
SPR owns 100 percent of the voting stock of SPPC.
The table below sets forth the shares of Sierra Pacific Resources 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.
<TABLE>
<CAPTION>
Common Shares
Beneficially Percent of Total Common
Owned as of Shares Outstanding as of
Name of Director or Nominee March 10, 1999 March 10, 1999
- ------------------------------------- ------------------------- --------------------------------------
<S> <C> <C>
Edward P. Bliss 14,419
Krestine M. Corbin 10,172
Theodore J. Day 20,613
Harold P. Dayton, Jr. 12,583
James R. Donnelley 18,840 No director or nominee
Richard N. Fulstone 14,845 for director owns in excess
Walter M. Higgins (1) 100 of one percent.
Malyn K. Malquist 43,243
James L. Murphy 10,318
Ronald K. Remington 8,338
Dennis E. Wheeler 9,250
Robert B. Whittington 13,214
-------------------------
175,935
=========================
</TABLE>
85
<PAGE>
<TABLE>
<CAPTION>
Common Shares
Beneficially Percent of Total Common
Owned as of Shares Outstanding as of
Executive Officers March 10, 1999 March 10, 1999
- -------------------------------------- -------------------------- ------------------------------------
<S> <C> <C>
Walter M. Higgins (1) 100
Malyn K. Malquist 43,243
William E. Peterson 22,451 No executive officer owns
Mark A. Ruelle 10,022 in excess of one percent
Mary Jane L. Willier 6,318
Randy G. Harris 8,803
--------------------------
90,937
==========================
All directors and executive officers 297,719
as a group (a) (b) (c)
==========================
</TABLE>
(1) Mr. Higgins resigned from his position of Chairman, President and Chief
Executive Officer on January 14, 1998.
(a) Includes shares acquired through participation in the Employee stock
Purchase Plan and/or the 401(k) plan.
(b) The number of shares beneficially owned includes shares which 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. Share beneficially owned pursuant to stock options granted
to Messrs. Higgins, Malquist, Peterson, Ruelle, Harris, Ms. Willier, and
all directors and executive officers as a group are -0-, 37,915, 18,913,
8,589, 5,833, 5,833 and 98,241 shares, respectively. Shares beneficially
owned as a result of performance shares earned by Messrs. Higgins,
Malquist, Peterson, Ruelle, Harris, Ms. Willier, and all directors and
officers as a group are 0, 1,156, 592, 494, 259, 400, and 1,965,
respectively.
(c) Included in the shares beneficially owned by the Directors are 71,737
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
SPR has entered to an agreement with Hale Day Gallagher Co., a real estate
brokerage and investment company, to act as broker for the sale of a property
owned by Lands of Sierra, Inc., a subsidiary of SPR. The eventual sale of the
property will result in Hale Day Gallagher Co. receiving a standard brokerage
commission not to exceed 5% of the selling price. Mr. T.J. Day, a senior
partner of Hale Day Gallagher Co. and a Director of the Company, has no
relationship with, or interest in, the transaction, will receive no part of the
commission, and will receive no direct or indirect benefit from the transaction.
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
86
<PAGE>
Wedge, which has performed legal services for Sierra Pacific Power Company since
1920 and for Sierra Pacific Resources and all of its subsidiaries from their
inception, continues to perform legal work for the Company. Mr. Peterson's
spouse, an equity partner in the firm since 1982, has performed work for the
Company 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 the Company's voluntary severance offering in
December 1995. Ms. Oldham is the spouse of Steven C. Oldham, Vice President
Transmission Business Group and Strategic Development for Sierra Pacific Power
Company. Ms. Oldham, a licensed attorney in Nevada and California, has
continued to perform specialized legal services in the water resources area for
the Company on a contract basis.
In April 1994, Mr. Malquist, who was elected President and Chief Executive
Officer on January 13, 1998, received a $92,000 interest-free loan related to
his employment arrangement with the Company. The loan is payable in four equal
annual installments. Any installment due on any anniversary date on which Mr.
Malquist is employed by the Company will be discharged by the Company in
consideration for services rendered during the previous year.
CHANGE IN CONTROL AGREEMENT
SPR has entered into severance agreements with certain key executives,
including the individuals named in the Summary Compensation Table. These
agreements provide that, upon termination of the executive's employment within
twenty-four months following a change in control of SPR (as defined in the
agreements) either (a) by SPR for reasons other than cause (as defined in the
agreements), death or disability, or (b) by the executive for good reason (as
defined by 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 the Company
and the acquirer)), the executive will receive certain payments and benefits.
These severance payments and benefits include (i) a lump sum payment equal to
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 be continued to participate in the Company's retirement plans for
an additional 3 years (or, in the case of the Company'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 thirty-six (36) months immediately following
termination of employment. Except for Mr. Malquist, the agreements also provide
that if any compensation paid, or benefit provided, to the executive, whether or
not 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. In the case of Mr. Malquist, the agreement
provides that SPR will pay an additional amount to hold him harmless from such
tax. 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
87
<PAGE>
Towers Perrin, the national compensation and benefits consulting firm described
above, and Skadden, Arps, Slate, Meager & 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.
88
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements, Financial Statement Schedules and Exhibits
<TABLE>
<CAPTION>
Page
----
<S> <C>
1. Financial Statements:
Report of Independent Auditors........................... 47
Consolidated Balance Sheets as of
December 31, 1998 and 1997............................. 2
Consolidated Statements of Income for the Years
Ended December 31, 1998, 1997 and 1996................. 2
Consolidated Statements of Common Shareholder's Equity
for the Years Ended December 31, 1998, 1997 and 1996... 2
Consolidated Statements of Cash Flows for the
Years Ended December 31, 1998, 1997 and 1996........... 2
Consolidated Statements of Capitalization as of
December 31, 1998 and 1997............................. 2
Notes to Consolidated Financial Statements............... 53-73
2. Financial Statement Schedules:
Report of Independent Auditors........................... 91
Schedule II-Valuation and Qualifying Accounts............ 92
</TABLE>
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 93-100
(b) Reports on Form 8-K
None.
89
<PAGE>
SIGNATURES
----------
Pursuant to the requirements of Section 13 and 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
SIERRA PACIFIC POWER COMPANY
By: /s/ Malyn K. Malquist
------------------------
Malyn K. Malquist
President and Chief Executive Officer
March 19, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on the 19th day of March, 1999.
<TABLE>
<S> <C>
/s/ Mark A. Ruelle /s/ Mary O. Simmons
- ------------------------------------- -------------------------------------
Mark A. Ruelle Mary O. Simmons
Senior Vice President, Controller
Chief Financial Officer and Treasurer (Principal Accounting Officer)
(Principal Financial Officer)
/s/ Edward P. Bliss /s/ James L. Murphy
- ------------------------------------- ------------------------------------
Edward P. Bliss James L. Murphy
Director Director
/s/ Krestine M. Corbin /s/ Ronald K. Remington
- ------------------------------------- ------------------------------------
Krestine M. Corbin Ronald K. Remington
Director Director
/s/ Theodore J. Day /s/ Dennis E. Wheeler
- ------------------------------------- -------------------------------------
Theodore J. Day Dennis E. Wheeler
Director Director
/s/ Harold P. Dayton, Jr. /s/ Robert B. Whittington
- ------------------------------------- -------------------------------------
Harold P. Dayton, Jr. Robert B. Whittington
Director Director
/s/ James R. Donnelley /s/ Malyn K. Malquist
- ------------------------------------- -------------------------------------
James R. Donnelley Malyn K. Malquist
Director Director
/s/ Richard N. Fulstone
- -------------------------------------
Richard N. Fulstone
Director
</TABLE>
90
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholder of
Sierra Pacific Power Company
Reno, Nevada
We have audited the consolidated financial statements of Sierra Pacific Power
Company and subsidiaries as of December 31, 1998 and 1997, and for each of the
three years in the period ended December 31, 1998, and have issued our report
thereon dated January 29, 1999 (February 12, 1999 as to Notes 1 and 3). Our
audits also included the financial statement schedule listed in the table of
contents on page 89. This financial statement schedule is the responsibility of
the Corporation's management. Our responsibility is to express an opinion based
on our audits. In our opinion, such financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Reno, Nevada
February 12, 1999
91
<PAGE>
Sierra Pacific Power Company
Schedule II - Valuation and Qualifying Accounts
For The Years Ended December 31, 1998, 1997 and 1996
(Dollars in Thousands)
<TABLE>
<CAPTION>
Provision for
Uncollectible
Accounts
--------------
<S> <C>
Balance at January 1, 1996 $ 1,543
Provision charged to income 1,880
Amounts written off, less recoveries (1,227)
--------------
2,196
Balance at January 1, 1997 2,196
Provision charged to income 1,411
Amounts written off, less recoveries (1,903)
--------------
1,704
Balance at January 1, 1998 1,704
Provision charged to income 3,686
Amounts written off, less recoveries (1,929)
--------------
$ 3,461
--------------
</TABLE>
92
<PAGE>
SIERRA PACIFIC POWER COMPANY
1998 FORM 10-K EXHIBIT INDEX
Exhibits filed with this Form 10-K are denoted with an asterisk (*). The
other listed exhibits have been previously filed with the Securities and
Exchange Commission and are incorporated herein by reference.
(3)
. Restated Articles of Incorporation of the Company dated May 19,
1987 (originally filed as Exhibit (3)(A) to the 1987 Form 10-K -
refiled as Exhibit (3)(A) to the 1993 Form 10-K)
. Certificate of Amendments dated August 26, 1992 to Restated
Articles of Incorporation of the Company dated May 19, 1987, in
connection with the Company's preferred stock (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 the Company dated May
19, 1987, in connection with the Company's Series C Preferred Stock
(Exhibit 4.1 to Form 8-K dated August 26, 1992)
. Certificate of Designation, Preferences and Rights dated August 31,
1992 to Restated Articles of Incorporation of the Company dated May
19, 1987, in connection with the Company's Series G Preferred Stock
(Exhibit 4.2 to Form 8-K dated August 26, 1992)
. Certificate of Designation, Preferences and Rights dated August 31,
1992 to Restated Articles of Incorporation of the Company dated May
19, 1987, in connection with the Company's Class A Series 1
Preferred Stock (Exhibit 4.3 to Form 8-K dated August 26, 1992)
. By-laws of the Company, as amended through June 30, 1988 (Exhibit
(3)(A) to the 1989 Form 10-K)
. Articles of Incorporation of Pinon Pine Corp., dated December 11,
1995 (Exhibit (3)(A) to the 1995 Form 10-K)
. Articles of Incorporation of Pinon Pine Investment Co., dated
December 11, 1995 (Exhibit (3)(B) to the 1995 Form 10-K)
. 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 (Exhibit (3)(C) to the 1995
Form 10-K)
. By-laws of the Company, in its entirety, as amended through
November 13, 1996 (Exhibit (3)(A) to the 1996 Form 10-K)
93
<PAGE>
(4)
. Mortgage Indentures of the Company defining the rights of the
holders of the Company's First Mortgage Bonds: Original Indenture
(Exhibit 7-A to Registration No. 2-7475); Ninth Supplemental
Indenture (Exhibit 2-M to Registration No. 2-59509); Tenth
Supplemental Indenture (Exhibit 4-K to Registration No. 2-23932);
Eleventh Supplemental Indenture (Exhibit 4-L to Registration No. 2-
26552); Twelfth Supplemental Indenture (Exhibit 4-Lto Registration
No. 2-36982); Sixteenth Supplemental Indenture (Exhibit 2-Y to
Registration No. 2-53404); Nineteenth Supplemental Indenture
(originally filed as Exhibit (2)(B) to the 1978 Form 10-K - refiled
as Exhibit (4)(A) to the 1991 Form 10-K; Twentieth Supplemental
Indenture (originally filed as Exhibit (2)(C) to the 1978 Form
10-K-refiled as Exhibit (4)(B) to the 1991 Form 10-K); Twenty-
Seventh Supplemental Indenture (Exhibit (4)(A) to the 1989 Form
10-K); Twenty-Eighth Supplemental Indenture (Exhibit (4)(A) to the
1992 Form 10-K); Twenty-Ninth Supplemental Indenture (Exhibit D to
Form 8-K dated July 15, 1992 in connection with the Company's
medium-term note program); Thirtieth Supplemental Indenture
(Exhibit (4)(B) to the 1992 Form 10-K); Thirty-First Supplemental
Indenture (Exhibit (4)(C) to the 1992 Form 10-K); Thirty-Second
Supplemental Indenture (Exhibit 4.6 to Registration No.99-69550);
Thirty-Third Supplemental Indenture (Exhibit C to Form 8-K dated
October 20, 1993 in connection with the Company's medium-term note
program)
. Collateral Trust Indenture dated June 1, 1992 between the Company
and Bankers Trust Company, as Trustee, relating to the Company's
medium-term Note program (Exhibit B to Form 8-K dated July 15, 1992
in connection with the Company's medium-term note program)
. First Supplemental Indenture dated June 1, 1992 to Collateral Trust
Indenture dated June 1, 1992 between the Company and Bankers Trust
Company, as Trustee, relating to the Company's medium-term note
program (Exhibit C to Form 8-K dated July 15, 1992 in connection
with the Company's medium-term note program)
. Second Supplemental Indenture dated October 1, 1993 to Collateral
Trust Indenture dated June 1, 1992 between the Company and Bankers
Trust Company, as Trustee, relating to the Company's medium-term
note program (Exhibit B to Form 8-K dated October 20, 1993 in
connection with the Company's medium-term note program)
. Form of Medium-Term Global Floating Rate Note, Series A (Exhibit E
to Form 8-K dated July 15, 1992 in connection with the Company's
medium-term note program)
. Form of Medium-Term Global Floating Rate Note, Series B (Exhibit D
to Form 8-K dated October 20, 1993 in connection with the Company's
medium-term note program)
94
<PAGE>
(4) - Continued
. Distribution Agreement to final forms of exhibits to the Company's
Registration Statement (No. 333-1374) in connection with its
offering of $80 million of Collateralized Debt Securities (the Debt
Securities) subsequently referred to as Series C Medium Term Notes
and Collateralized Debt Securities. (Exhibit A on Form 8-K dated
March 11, 1996).
. Third Supplemental Indenture dated as of February 1, 1996 to
Collateral Trust Indenture dated as of June 1, 1992 between the
Company and Bankers Trust Company, as Trustee, relating to the
Company's Medium Term Note Program. (Exhibit B to Form 8-K dated
March 11, 1996).
. Thirty-fourth Supplemental Indenture dated as of February 1, 1996
to Indenture of Mortgage dated as of December 1, 1940 defining the
rights of the Company's First Mortgage Bonds. (Exhibit C to Form 8-
K dated March 11, 1996).
. Form of Medium-Term Global Fixed Rate Note, Series C. (Exhibit D to
Form 8-K dated March 11, 1996).
. Amended and Restated Declaration of Trust of Sierra Pacific Power
Capital I (the Trust) dated July 24, 1996 in connection with the
offering of the Preferred Securities of the Trust. (Exhibit 4.1
Form 8-K dated August 2, 1996)
. Indenture between the Company and IBJ Schroder Bank and Trust
Company as Trustee dated July 1, 1996 in connection with the
offering of the Preferred Securities of the Trust. (Exhibit 4.2
Form 8-K dated August 2, 1996)
. First Supplemental Indenture to the Indenture used in connection
with the issuance of Junior Subordinated Debentures dated July 24,
1996 in connection with the offering of the Preferred Securities of
the Trust. (Exhibit 4.3 Form 8-K dated August 2, 1996).
. Guarantee with respect to Preferred Securities dated July 29, 1996
in connection with the offering of the Preferred Securities of the
Trust. (Exhibit 4.4 Form 8-K dated August 2, 1996).
. Guarantee with respect to Common Securities dated July 29, 1996 in
connection with the offering of the Preferred Securities of the
Trust. (Exhibit 4.5 Form 8-K dated August 2, 1996).
. Form of medium-term Global Fixed Rate Note, Series D. (Exhibit D to
Form 8-K dated March 10, 1997.
95
<PAGE>
(10)
. Coal Sales Agreement dated May 16, 1978 between the Company and
Coastal States Energy Company (confidential portions omitted and
filed separately with the Securities and Exchange Commission)
(Exhibit 5-GG to Registration No. 2-62476)
. Amendment No. 1 dated November 8, 1983 to Coal Sales Agreement
dated May 16, 1978 between the Company and Coastal States Energy
Company (originally filed as Exhibit (10)(B) to the 1983 Form
10-K -refiled as Exhibit (10)(B) to the 1991 Form 10-K)
. Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement
dated May 16, 1978 between the Company and Coastal States Energy
Company (originally filed as Exhibit (10)(G) to the 1986 Form 10-K
as amended by Form 8 filed May 19, 1987 -refiled as Exhibit (10)(A)
to the 1993 Form 10-K)
. Amendment No. 3 dated May 8, 1992 to Coal Sales Agreement dated May
16, 1978 between the Company and Coastal States Energy Company
(Exhibit (10)(B) to the 1992 Form 10-K; confidential portions
omitted and filed separately with the Securities and Exchange
Commission)
. Coal Purchase Contract dated June 19, 1986 between the Company,
Black Butte Coal Company and Idaho Power Company (originally filed
as Exhibit (10)(B) to the 1986 Form 10-K - refiled as Exhibit
(10)(C) to the 1992 Form 10-K)
. Settlement Agreement and Mutual Release dated May 8, 1992 between
the Company and Coastal States Energy Company (Exhibit (10)(D) to
the 1992 Form 10-K; confidential portions omitted and filed
separately with the Securities and Exchange Commission)
. Interconnection Agreement dated May 29, 1981 between the Company
and Idaho Power Company (originally filed as Exhibit (10)(A) to the
1981 Form 10-K -refiled as Exhibit (10)(C) to the 1991 Form 10-K)
. Amendatory Agreement dated February 14, 1992 to Interconnection
Agreement dated May 29, 1981 between the Company and Idaho Power
Company (Exhibit (10)(D) to the 1991 Form 10-K)
. Agreement dated February 23, 1989 between the Company and Idaho
Power Company for the supply of power and energy (Exhibit (10)(A)
to the 1988 Form 10-K)
. Cooperative Agreement dated July 31, 1992 between the Company and
the United States Department of Energy in connection with the Pinon
Pine Integrated Coal Gasification Combined Cycle Project (Exhibit
(10)(H) to the 1992 Form 10-K)
96
<PAGE>
(10) - Continued
. Revised Intercompany Pool Agreement dated July 19, 1982 pertaining
to the Company's membership (originally filed as Exhibit (10)(C) to
the 1982 Form 10-K- refiled as Exhibit (10)(E) to the 1991 Form 10-
K)
. Agreement dated November 7, 1986 between the Company and Western
Systems Power Pool (Exhibit (10)(C) to the 1988 Form 10-K)
. Memorandum dated October 1, 1988 to Agreement dated November 7,
1986 between the Company and Western Systems Power Pool (Exhibit
(10)(D) to the 1988 Form 10-K)
. General Transfer Agreement dated February 25, 1988 between the
Company and the United States of America Department of Energy
acting by and through the Bonneville Power Administration (Exhibit
(10)(E) to the 1988 Form 10-K)
. Rail Transportation Contract dated June 30, 1986 between the
Company and Idaho Power Company as shippers and Union Pacific and
Western Pacific Railroad Companies as carriers (originally
confidentially filed as Exhibit (10)(H) to the 1986 Form 10-K as
amended by Form 8 filed May 19, 1987 - refiled as Exhibit (10)(C)
to the 1993 Form 10-K)
. Addendum dated October 9, 1993 to Rail Transportation Contract
dated June 30, 1986 between the Company and Idaho Power Company as
shippers and Union Pacific Railroad Companies as carriers (Exhibit
(10)(D) to the 1993 Form 10-K)
. Financing Agreement dated March 1, 1987 between the 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 (originally
filed as Exhibit (10)(C) to the 1987 Form 10-K - refiled as Exhibit
(10)(E) to the 1993 Form 10-K)
. Financing Agreement dated March 1, 1987 between the 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
(originally filed as Exhibit (10)(E) to the 1987 Form 10-K-refiled
as Exhibit (10)(F) to the 1993 Form 10-K)
. Financing Agreement dated June 1, 1987 between the 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 (originally filed as Exhibit
(10)(G) to the 1987 Form 10-K - refiled as Exhibit (10)(G) to the
1993 Form 10-K)
97
<PAGE>
(10) - Continued
. Financing Agreement dated December 1, 1987 between the 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 (originally filed as Exhibit
(10)(I) to the 1987 Form 10-K - refiled as Exhibit (10)(H) to the
1993 Form 10-K)
. Financing Agreement dated September 1, 1990 between the Company and
Washoe County, Nevada relating to the Washoe County, Nevada Gas
Facilities Revenue Bonds (Sierra Pacific Power Company Project)
Series 1990 (Exhibit (10)(C) to the 1990 Form 10-K)
. Financing Agreement dated December 1, 1990 between the Company and
Washoe County, Nevada relating to the Washoe County, Nevada Water
Facilities Revenue Bonds (Sierra Pacific Power Company Project)
Series 1990 (Exhibit (10)(E) to the 1990 Form 10-K)
. First Amendment dated August 12, 1991 to Financing Agreement dated
December 1, 1990 between the Company and Washoe County, Nevada
relating to the Washoe County, Nevada Water Facilities Revenue
Bonds (Sierra Pacific Power Company Project) Series 1990 (Exhibit
(10)(J) to the 1991 Form 10-K)
. Letter of Credit, Reimbursement and Security Agreement dated
December 12, 1990 between the Company and Union Bank of Switzerland
relating to the Washoe County, Nevada Water Facilities Revenue
Bonds (Sierra Pacific Power Company Project) Series 1990 (Exhibit
(10)(F) to the 1990 Form 10-K)
. Financing Agreement dated June 1, 1993 between the Company and
Washoe County, Nevada relating to the Washoe County, Nevada Water
Facilities Refunding Revenue Bonds (Sierra Pacific Power Company
Project) Series 1993A (Exhibit (10) (I) to the 1993 Form 10-K)
. Financing Agreement dated June 1, 1993 between the 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 (Exhibit (10) (J) to the 1993 Form
10-K)
. Credit Agreement dated January 3, 1995 by and among the Company,
The Lenders Parties hereto from time to time and Mellon Bank, N.A.,
as Agent. (Exhibit (10)(A) to the 1994 Form 10-K)
. Agreement dated May 1, 1991 between the Company and the Inter-
national Brotherhood of Electrical Workers (Exhibit (10)(K) to the
1991 Form 10-K)
98
<PAGE>
(10) - Continued
. Ratified changes to the Agreement between the Company and the
International Brotherhood of Electrical Workers dated October 31,
1994 (Exhibit (10)(B) to the 1994 Form 10-K)
. Lease dated January 30, 1986 between the Company and Silliman
Associates Limited Partnership relating to the Company's corporate
headquarters building (originally filed as Exhibit (10)(C) to the
1986 Form 10-K - refiled as Exhibit (10)(I) to the 1992 Form 10-K)
. Letter of Amendment dated May 18, 1987 to Lease dated January 30,
1986 between the Company and Silliman Associates Limited
Partnership relating to the Company's corporate headquarters
building (Exhibit (10)(L) to the 1987 Form 10-K- refiled as Exhibit
(10) (K) to the 1993 Form 10-K)
. Natural gas Transportation Service Agreement, dated January 11,
1995 between the Company and Tuscarora Gas Transmission Company
(Filed with 1995 Form 10-K)
. Fixed-Price Turn-Key Construction Agreement, dated December 15,
1995 between the Company and Pinon Pine Company, L.L.C (Filed with
1995 Form 10-K)
. Operation and Maintenance Agreement, dated December 15, 1995
between the Company and Pinon Pine Company, L.L.C. (Filed with 1995
Form 10-K)
. Syngas Purchase Agreement, dated December 15, 1995 between the
Company and Pinon Pine Company, L.L.C. (Filed with 1995 Form 10-K)
. The Amended and Restated Nonqualified Deferred Compensation Plan in
which any director or any executive officer of the Company may
participate. The Plan was amended and restated January 1, 1996
(Filed with 1996 Form 10-K)
. Distribution Agreement related to the Company's offering of $35
million Collateralized Medium-term Notes, Series D (Exhibit A on
Form 8-K, dated March 10, 1997)
. Change in Control Agreement dated February 18, 1997 by and among
Sierra Pacific Resources and the following officers (individually):
Gerald W. Canning, Jeffrey L. Ceccarelli, Randy G. Harris, Malyn K.
Malquist, Steven C. Oldham, Victor H. Pena, William E. Peterson,
Mark A. Ruelle, Mary O. Simmons, Doug Ponn, and Mary Jane Willier.
. Agreement dated January 1, 1998 between the Company and the
International Brotherhood of Electrical Workers. (Filed with 1997
Form 10-K)
. Notice of Termination of Power Purchase from PacifiCorp under the
Interconnection Agreement of May 19, 1971.
99
<PAGE>
(11)
. The Company is a wholly owned subsidiary and, in accordance with
Paragraph 6 of SFAS No. 128 (Earnings Per Share), earnings per
share data have been omitted.
(12) (A)
. Calculation of Pre-Tax Interest Coverages for the Periods 1998,
1997 and 1996.
(16)
. Letter from Coopers & Lybrand L.L.P. dated November 21, 1996
regarding the change in certifying accountants. (Exhibit filed with
Form 8-K/A dated November 22, 1996)
(21)
. Subsidiaries of the Registrant:
Pinon Pine Company
Pinon Pine Investment Company
Sierra Pacific Power Capital Trust I (The Trust)
(23)
. Consent of Independent Auditors in connection with the Registration
Statement of Sierra Pacific Power Company (File No. 333-17041),
regarding its issuance of Series D Medium-Term Notes. (Filed with
1997 10-K)
(27)
*(A)
The Financial Data Schedule containing summary financial information
extracted from the consolidated financial statements filed on Form
10-K from the twelve month period ending December 31, 1998.
100
<PAGE>
PURCHASE AND SALE
AND ASSIGNMENT AND ASSUMPTION AGREEMENT
DATED AS OF FEBRUARY 9, 1999
BY AND BETWEEN
GENERAL ELECTRIC CAPITAL CORPORATION
AND
SIERRA PACIFIC POWER COMPANY
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
Page
<S> <C>
ARTICLE I..........................................................................................................2
1.1 General 2
1.2 Definitions................................................................................................2
1.3 Interpretation.............................................................................................5
ARTICLE II.........................................................................................................5
PURCHASE AND SALE AND ASSIGNMENT AND ASSUMPTION..................................................................5
2.1 Purchase and Sale and Assignment..........................................................................5
2.2 Payment of the Purchase Price.............................................................................5
2.3 Assumption................................................................................................5
ARTICLE III........................................................................................................6
REPRESENTATIONS AND WARRANTIES OF SELLER.........................................................................6
3.1 Corporate Status; Authority of Seller; Enforceability.....................................................6
3.2 Documents.................................................................................................7
3.3 Liens 7
3.4 Assignment................................................................................................7
3.5 Compliance with Laws......................................................................................7
3.6 Litigation................................................................................................7
3.7 Bankruptcy................................................................................................7
3.8 Personnel Identification..................................................................................8
3.9 Capitalization; Subsidiaries..............................................................................8
3.10 Title to Purchased Shares.................................................................................8
3.11 Tax Matters...............................................................................................8
3.12 Real Property............................................................................................10
3.13 Consents 10
3.14 Broker's or Consultant's Fees............................................................................10
3.15 Banking Arrangements.....................................................................................10
3.16 Powers of Attorney.......................................................................................10
3.17 Loans 10
ARTICLE IV........................................................................................................11
REPRESENTATIONS AND WARRANTIES OF PURCHASER.....................................................................11
4.1 Corporate Status.........................................................................................11
4.2 Due Authorization........................................................................................11
4.3 Authority of Purchaser...................................................................................11
4.4 Enforceability...........................................................................................11
4.5 Consents 11
4.6 Broker's or Consultant's Fees............................................................................11
</TABLE>
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<PAGE>
<TABLE>
<S> <C>
ARTICLE V.........................................................................................................12
COVENANTS.......................................................................................................12
5.1 Required Filings.........................................................................................12
5.2 Pre-Closing Taxes........................................................................................12
5.3 Tax Reports; Returns.....................................................................................12
5.4 Optional Section 338(h)(10) Elections....................................................................12
5.5 Further Assurance........................................................................................13
ARTICLE VI........................................................................................................13
CONDITIONS PRECEDENT TO PURCHASER'S OBLIGATIONS.................................................................13
6.1 Obligations to be Satisfied on or Prior to Closing Date..................................................13
ARTICLE VII.......................................................................................................14
CONDITIONS PRECEDENT TO SELLER'S OBLIGATIONS....................................................................14
7.1 Obligations to Be Satisfied on or Prior to Closing Date..................................................14
ARTICLE VIII......................................................................................................15
CLOSING.........................................................................................................15
8.1 Time and Place...........................................................................................15
8.2 Closing Transactions.....................................................................................15
8.3 Deliveries by Seller to Purchaser........................................................................15
8.4 Deliveries by Purchaser to Seller........................................................................16
ARTICLE IX........................................................................................................16
INDEMNIFICATION...............................................................................................16
9.1 Indemnification by Seller................................................................................16
9.2 Indemnification by Purchaser.............................................................................17
9.3 Procedure for Indemnification............................................................................18
9.4 Payment 18
ARTICLE X.........................................................................................................18
MISCELLANEOUS PROVISIONS........................................................................................18
10.1 Post-Closing Deliveries..................................................................................18
10.2 Notices 19
10.3 Assignment...............................................................................................19
10.4 Benefit of the Agreement.................................................................................20
10.5 Exhibits and Schedules...................................................................................20
10.6 Headings 20
10.8 Modifications and Waivers................................................................................20
10.9 Counterparts.............................................................................................20
10.10 Severability.............................................................................................20
10.11 GOVERNING LAW............................................................................................20
</TABLE>
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<PAGE>
<TABLE>
<S> <C>
10.12 Expenses 21
10.13 Tax Consequences.........................................................................................21
</TABLE>
EXHIBIT
- -------
Exhibit A Form of Withholding Certificate
-civ-
<PAGE>
PURCHASE AND SALE
-----------------
AND ASSIGNMENT AND ASSUMPTION AGREEMENT
---------------------------------------
THIS PURCHASE AND SALE AND ASSIGNMENT AND ASSUMPTION AGREEMENT is entered
into as of this 9th day of February, 1999, by and between SIERRA PACIFIC POWER
COMPANY, a Nevada corporation (together with its successors and permitted
assigns, "Purchaser"), and GENERAL ELECTRIC CAPITAL CORPORATION, a New York
---------
corporation (together with its successors and permitted assigns, "Seller").
------
RECITALS
--------
WHEREAS, Purchaser and Seller are parties to that certain Membership
Interest Acquisition Agreement dated as of December 15, 1995 (the "Membership
----------
Interest Acquisition Agreement") together with Pinon Pine Corp., a Nevada
- ------------------------------
corporation ("Member A1"), Pinon Pine Investment Co., a Nevada corporation
---------
("Member A2") (collectively, Member A1 and Member A2 shall be referred to as the
- -----------
"A Members"), and GPSF-B Inc., a Delaware corporation ("Member B"), pursuant to
--------- --------
which (a) each of Purchaser and Seller made certain contributions of tangible
and intangible property to the A Members and to Member B, respectively, in
exchange for the issuance of shares of the capital stock of the A Members and
Member B, respectively, and (b) each of the A Members and Member B made certain
contributions of tangible and intangible property to Pinon Pine Company, L.L.C.,
a Delaware limited liability company (the "Company"), in exchange for their
-------
respective interests in the Company;
WHEREAS, the Company was formed pursuant to that certain Agreement of
Limited Liability Company of Pinon Pine Company, L.L.C. dated as of December 15,
1995 (the "LLC Agreement") by and among the A Members and Member B for the
-------------
purpose of owning and operating the Facility;
WHEREAS, Purchaser and the Company have entered into that certain Fixed-
Price Turn-Key Construction Agreement dated as of December 15, 1995 (the
"Construction Agreement") pursuant to which Purchaser agreed to construct and
- -----------------------
start-up the Facility;
WHEREAS, Purchaser has failed to complete the construction of the Facility
before June 30, 1998 to the satisfaction of Member B as required by Section 4.3
-----------
of the Construction Agreement and the Company's sole remedy is to cause
Purchaser to acquire the Facility;
WHEREAS, in lieu of acquiring the Facility, Purchaser desires to exercise
its option under Section 4.3(a) of the Construction Agreement to acquire the
--------------
stock of Member B;
WHEREAS, Member B is in the business of holding a membership interest in
the Company ("Member B's Interest") (the "Business");
------------------- --------
<PAGE>
WHEREAS, Seller owns, through GE Capital Services Structured Finance Group,
Inc., a Delaware corporation and a wholly-owned subsidiary of Seller ("GESFG"),
-----
all of the issued and outstanding shares of capital stock of Member B,
consisting of 1,000 shares of common stock, $1.00 par value (the "Shares");
------
WHEREAS, Purchaser desires to acquire from Seller and Seller desires to
sell and transfer to Purchaser, the Investor Interest (excluding the Reserved
Rights (each as defined in Section 1.2 hereof)), all subject to the terms and
-----------
conditions set forth below;
NOW, THEREFORE, in consideration of the foregoing Recitals and the mutual
agreements and covenants contained herein, and for other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged,
Purchaser and Seller hereby agree as follows:
ARTICLE I
---------
DEFINITIONS
-----------
I.1 General. Each term defined in the first paragraph of this Agreement
-------
and in the Recitals shall have the meaning set forth above whenever used herein,
unless otherwise expressly provided or unless the context clearly requires
otherwise.
I.2 Definitions. As used herein, the following terms shall have the
-----------
meanings ascribed to them in this Section 1.2 or, to the extent not defined in
-----------
this Section 1.2, in Appendix A to the Membership Interest Acquisition
-----------
Agreement:
A Members. As defined in the Recitals hereto.
---------
Adverse Consequences. All allegations, charges, complaints, actions,
--------------------
suits, proceedings, hearings, investigations, claims, demands, judgments,
orders, decrees, stipulations, injunctions, damages, dues, penalties, fines,
costs, amounts paid in settlement, Liabilities, Taxes, interest, Liens, losses,
expenses and fees, including all accounting, consultant and attorneys' fees and
court costs, costs of expert witnesses and other expenses of litigation.
Affiliate. As set forth in Rule 12b-2 of the regulations promulgated
---------
under the Securities Exchange Act of 1934.
Agreement. This Purchase and Sale and Assignment and Assumption
---------
Agreement, together with all Exhibits and Schedules referred to herein, as
amended, modified or supplemented from time to time in accordance with the terms
hereof.
Authority. Any governmental, regulatory or administrative body,
---------
agency or authority, any court of judicial authority, any arbitrator or any
public, private or industry regulatory authority, whether foreign, federal,
state or local.
Business. As defined in the Recitals hereto.
--------
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<PAGE>
Closing. The actual conveyance, transfer, assignment and delivery of
-------
the Investor Interest to Purchaser in exchange for the consideration payable to
Seller pursuant to this Agreement.
Closing Date. Friday, February 12, 1999, or such other date as
------------
Purchaser and the Seller may mutually agree in writing, in either case, upon
which the Closing shall occur.
Code. Internal Revenue Code of 1986.
----
Company. As defined in the Recitals hereto.
-------
Construction Agreement. As defined in the Recitals hereto.
----------------------
HSR Act. The Hart-Scott-Rodino Antitrust Improvements Act of 1976,
-------
as amended.
Indemnified Party. As defined in Section 9.3.
----------------- -----------
Indemnifying Party. As defined in Section 9.3.
------------------ -----------
Investor Interest (i) All of the Seller's and GESFG's right, title
-----------------
and interest in the Shares, (ii) all of Seller's rights as Investor in, to and
under the Documents (other than the Reserved Rights) and (iii) all of Seller's
obligations as Investor under the Documents to the extent arising or to be
performed on or after the Closing Date.
IRS. Internal Revenue Service.
---
Law. Any law, statute, regulation, rule, ordinance, requirement,
---
announcement or other binding action or requirement of an Authority.
Liabilities. Any obligation or liability (whether known or unknown,
-----------
whether asserted or unasserted, whether absolute or contingent, whether accrued
or unaccrued, whether liquidated or unliquidated and whether due or to become
due), including, without limitation, any liability for Taxes.
Lien. Any lien (statutory or other), mortgage, pledge, hypothecation,
----
assignment, deposit arrangement, encumbrance or preference, priority or security
agreement or preferential arrangement of any kind or nature whatsoever
(including, without limitation, the interest of a vendor or lessor under any
conditional sale, capitalized lease or other title retention agreement).
LLC Agreement. As defined in the Recitals hereto.
-------------
Member A1. As defined in the Recitals hereto.
---------
-3-
<PAGE>
Member A2. As defined in the Recitals hereto.
---------
Member B. As defined in the Recitals hereto.
--------
Member B's Interest. As defined in the Recitals hereto.
-------------------
Membership Interest Acquisition Agreement. As defined in the
-----------------------------------------
Recitals hereto.
Order. Any decree, order, judgment, writ, award, injunction,
-----
stipulation or consent of or by an Authority.
Ordinary Course of Business. The ordinary course of business of
---------------------------
Member B in accordance with past custom and practice (including with respect to
quantity and frequency).
Person. Any natural person, corporation, limited liability company,
------
partnership, firm, joint venture, joint-stock company, trust, association,
Authority, unincorporated entity or organization of any kind.
Prior Claim. Any Claim, indemnity or other right to payment that
-----------
Seller may have as "Investor" under the Documents or as owner of the Shares, to
the extent such Claim accrues, arises from or relates to any period prior to the
Closing Date, whether known or unknown, contingent or otherwise; it being
understood that any such Claim, indemnity or other right to payment arising from
any payment or performance obligation under any Documents which by its terms is
to be paid or performed on or after the Closing Date is not to be considered a
Prior Claim.
Purchase Price. As defined in Section 2.2.
-------------- -----------
Purchaser. As defined in the paragraph preceding the Recitals.
---------
Purchaser Warranty Claim. As defined in Section 9.1(a).
------------------------ --------------
Reserved Rights. Any of the right, title and interest of Seller (and
---------------
its affiliates, successors and assigns (other than Purchaser and its successors
and assigns), agents, servants, representatives, directors and officers) in and
to each and every Prior Claim (but not to the exclusion of the Purchaser).
Section 338 Elections. As defined in Section 5.4.
--------------------- -----------
Section 338 Election Forms. As defined in Section 5.4.
-------------------------- -----------
Seller. As defined in the Recitals hereto.
------
Seller Warranty Claim. As defined in Section 9.2.
--------------------- -----------
-4-
<PAGE>
Seller's Knowledge. Seller's actual knowledge after due inquiry and
------------------
reasonable investigation.
Shares. As defined in the Recitals hereto.
------
Taxes. As defined in Section 3.11(a).
----- ---------------
Transaction Parties. Collectively, each party to the Membership
-------------------
Interest Acquisition Agreement.
I.3 Interpretation. Unless otherwise expressly provided or unless the
--------------
context requires otherwise, (a) all references in this Agreement to Articles,
Sections, Schedules and Exhibits shall mean and refer to Articles, Sections,
Schedules and Exhibits of this Agreement; (b) all references to statutes and
related regulations shall include all amendments of the same and any successor
or replacement statutes and regulations; (c) words using the singular or plural
number also shall include the plural and singular number, respectively; (d)
references to "hereof", "herein", "hereby" and similar terms shall refer to this
entire Agreement (including the Schedules and Exhibits hereto); and (e)
references to any Person shall be deemed to mean and include the successors and
permitted assigns of such Person (or, in the case of an Authority, Persons
succeeding to the relevant functions of such Person).
ARTICLE II
PURCHASE AND SALE AND ASSIGNMENT AND ASSUMPTION
-----------------------------------------------
II.1 Purchase and Sale and Assignment. Subject to the terms and
--------------------------------
conditions of this Agreement, and in reliance upon the representations,
warranties, covenants and agreements made in this Agreement by Seller and
Purchaser, Purchaser shall purchase and accept from Seller, and Seller shall
sell, transfer, convey, assign and deliver to Purchaser, on the Closing Date,
the Investor Interest (including without limitation causing GESFG to sell,
transfer, convey, assign and deliver to Purchaser the Shares) subject to Section
-------
2.3(b).
- ------
II.2 Payment of the Purchase Price. The purchase price (the "Purchase
----------------------------- --------
Price") payable by Purchaser to Seller in consideration for the Investor
- -----
Interest shall be Twenty-Nine Million Eight Hundred Seventy Thousand Four
Hundred Seventy-Three Dollars and Three Cents ($29,870,473.03) plus interest
from November 30, 1998 up to and including the Closing Date, at an interest rate
equal to the applicable pre-tax yield provided for in the definition of "Book
Investment" as defined in Appendix A to the Membership Interest Acquisition
Agreement, payable on the Closing Date by wire transfer of immediately available
federal funds to an account designated in writing to Purchaser by Seller in
writing prior to the Closing.
II.3 Assumption. (a) Upon the Closing Date, Purchaser accepts the
----------
assignment set forth above and confirms that it shall be deemed the Investor and
as such a party to the Documents, and Purchaser agrees to be bound by all of the
terms of and assumes all of the duties and obligations of the Investor pursuant
to the Documents (other than duties and obligations relating to Prior Claims and
Reserved Rights). From and after the Closing Date, Seller shall be
-5-
<PAGE>
released and discharged from, and shall not be responsible to Purchaser or to
any Person for, the discharge or performance of any duty or obligation as
Investor pursuant to or in connection with the Documents (other than duties or
obligations occurring or arising prior to the Closing Date or relating to Prior
Claims and Reserved Rights) and Purchaser shall be substituted in lieu of Seller
as Investor with respect to each of the Documents to which Seller is a party as
Investor. From and after the Closing Date, Purchaser shall not be responsible to
any Person for the discharge or performance of any duty or obligation of Seller
as Investor in connection with the Documents occurring or arising prior to the
Closing Date or any duty or obligation in connection with any Prior Claim or
Reserved Right.
(b) From and after the Closing Date, neither Seller nor any Affiliate
of Seller will claim any tax benefits, file any tax returns or take any other
action that would be inconsistent with the status of Purchaser as the sole owner
of the Investor Interest, including the Shares, for federal, state and local tax
purposes, or with the treatment of Purchaser as the owner of the Shares, except
for the period of Seller's ownership prior to the Closing Date.
ARTICLE III
REPRESENTATIONS AND WARRANTIES OF SELLER
----------------------------------------
As an inducement to Purchaser to enter into and perform its obligations
under this Agreement, and in consideration of the covenants of Purchaser
contained herein, Seller represents and warrants to Purchaser as of the date of
this Agreement and as of the Closing Date (which representations and warranties
shall survive the Closing regardless of what examinations, inspections, audits
and other investigations Purchaser has heretofore made, or may hereafter make,
with respect to such representations and warranties) as follows:
III.1 Corporate Status; Authority of Seller; Enforceability.
-----------------------------------------------------
(a) Each of Seller, GESFG and Member B is a corporation duly organized,
validly existing and in good standing under the laws of the state of its
organization and in each other jurisdiction where the failure to so qualify
could have a material adverse effect on its business, operations or condition or
on the Business. Each of Seller and Member B has the corporate power and
authority necessary to perform its obligations under the Documents.
(b) Seller has the corporate power and authority to execute and deliver
this Agreement and to perform its obligations hereunder. The execution, delivery
and performance by Seller of this Agreement have been duly authorized by all
necessary corporate action on its part and neither the execution and delivery
thereof, nor the consummation of the transactions contemplated thereby, nor
compliance by it with any of the terms and provisions thereof requires or will
require any approval of stockholders of, or approval or consent of any trustee
or holders of any indebtedness or obligations of Seller other than such consents
and approvals as have been obtained and are in full force and effect. This
Agreement has been duly executed and delivered by Seller and (assuming the due
authorization, execution, delivery by Purchaser) constitutes its legal, valid
and binding obligation enforceable against Seller in accordance with its terms,
-6-
<PAGE>
subject to bankruptcy, insolvency, reorganization and other laws affecting
creditors' rights generally and by general principles of equity (whether in a
proceeding at law or in equity).
(c) Except as may arise from the activities contemplated by the Documents,
neither the execution or delivery of this Agreement by Seller nor the
performance by Seller of its obligations under this Agreement will conflict with
or result in a breach of any of the terms or provisions of, or constitute a
default under, any contract, lease, license, franchise, permit, indenture,
mortgage, deed of trust, note agreement or other agreement or instrument to
which Seller, GESFG or Member B is a party or is bound, the articles of
incorporation or by-laws of Seller, GESFG or Member B or any applicable Law or
Order to which Seller, GESFG or Member B is a party or by which Seller, GESFG or
Member B is bound or would result in any Lien on the Shares or the Investor
Interest.
III.2 Documents. Each Document to which Seller, in its capacity as
---------
Investor, or Member B is a party has been duly authorized by all necessary
corporate action on behalf of Seller or Member B, and has been executed and
delivered by Seller or Member B. Seller has delivered to Purchaser the minutes
of all directors and shareholder meetings of Member B. As of the Closing Date,
Member B will not be a party to any contract or agreement other than the
Documents and such other documents which are contemplated by the Documents.
From and after the Closing Date, Member B will have no assets other than the
assets, rights and interests which are in connection with the Pinon Pine Project
and which are contemplated by the Documents. Member B was formed on October 2,
1995, and since such date has not conducted any business or incurred any
liability or obligation other than its obligations under the Documents or
obligations or liabilities arising from the activities contemplated by the
Documents.
III.3 Liens. Purchaser will acquire the Shares free of any Liens
-----
attributable to Member B, GESFG or Seller (other than Liens created pursuant to
the Documents).
III.4 Assignment. Except pursuant to this Agreement or the Documents,
----------
Member B has not assigned or transferred any of its right, title or interest in
or under the Documents, the Property or the Pinon Pine Project.
III.5 Compliance with Laws. Except as may result from the transactions
--------------------
contemplated by the Documents, Member B has complied with all, and is not in
violation of any, applicable Laws or Orders (including, without limitation, any
applicable building, zoning, environmental protection, occupational health and
safety, employment or disability rights law, ordinance or regulation) affecting
its properties or the operation of its Business.
III.6 Litigation. Except as may result from the transactions
----------
contemplated by the Documents, there are no actions, proceedings, claims, suits,
investigations, inquiries, or similar actions pending or, to the best of
Seller's Knowledge, threatened, against it, GESFG or Member B before any
Authority, arbitral or tribunal in law or equity that questions the validity or
enforceability of this Agreement or any Document to which Seller or Member B is
or is to become a party or that would materially and adversely affect Seller's,
GESFG's or Member B's
-7-
<PAGE>
ability to perform their respective obligations under this Agreement or the
Documents to which such person is a party.
III.7 Bankruptcy. There is not pending against Seller, GESFG or Member B
----------
any voluntary petition in bankruptcy or petition or answer seeking any
reorganization, liquidation, dissolution or similar relief under any federal or
state bankruptcy, insolvency, or other law relating to relief for debtors, and
neither Seller nor any Affiliate has sought or consented to or acquiesced in the
appointment of any trustee, receiver, conservator or liquidator of all or any
part of its properties or its interest in or Seller's, GESFG's or Member B's
rights to the Pinon Pine Project, the Investor Interest or the Shares. No court
of competent jurisdiction has entered an order, judgment, or decree approving a
petition filed against Seller, GESFG or Member B seeking any reorganization,
arrangement, composition, readjustment, liquidation, dissolution or similar
relief under any federal bankruptcy or insolvency act or other law relating to
relief for debtors, and no other liquidator has been appointed for the Seller,
GESFG or Member B or of all or any part of its properties or its rights to the
Pinon Pine Project, the Investor Interest or the Shares and no such action is
pending.
III.8 Personnel Identification. All officers and directors of Member B
------------------------
shall resign as of the Closing Date.
III.9 Capitalization; Subsidiaries. (a) The total number of shares of
----------------------------
capital stock and the par value thereof which Member B is authorized to issue
and the number of such shares which are issued and outstanding are as follows:
<TABLE>
<CAPTION>
Issued and
Class Authorized Shares Outstanding Shares
----- ----------------- ------------------
- ----------------------------------------------------------------------------------------------
<S> <C> <C>
Common Stock, $1.00 par value 1,000 1,000
- ----------------------------------------------------------------------------------------------
</TABLE>
No shares of Member B's capital stock are held as treasury stock.
(b) Except for Purchaser's option, which the Purchaser is exercising
hereunder, to acquire the Shares pursuant to Section 4.3 of the Construction
-----------
Agreement, there are no outstanding options, conversion rights, phantom stock
plans, warrants or other rights in existence to acquire from Member B any of its
shares of capital stock.
(c) The Shares have been duly and validly issued and are fully paid and
nonassessable and are not subject to any preemptive rights; and there are no
voting trust agreements or other contracts, agreements or arrangements
restricting voting or dividend rights or transferability with respect to the
outstanding shares of capital stock of Member B.
(d) Member B has not violated in any material respect any federal, state or
local Law in connection with the offer for sale or sale and issuance of its
outstanding shares of capital stock or any other securities issued by it.
-8-
<PAGE>
(e) Member B does not own any securities or any other direct or indirect
interest in any other Person other than those contemplated by the Documents.
III.10 Title to Purchased Shares. GESFG owns all of the Shares of
-------------------------
Member B. GESFG is of the record and beneficial owner of all of the issued and
outstanding capital stock of Member B. The Shares constitute all of the issued
and outstanding shares of capital stock of Member B and upon delivery of and
payment by Purchaser to Seller of the Purchase Price, Purchaser will acquire
good and marketable title to the Shares free and clear of all Liens.
III.11 Tax Matters.
-----------
(a) The term "Taxes" means all net income, capital gains, gross income,
-----
gross receipts, sales, use, transfer, ad valorem, franchise, profits, license,
capital, withholding, payroll, employment, excise, goods and services,
severance, stamp, occupation, premium, property, assessments or other
governmental charges of any kind whatsoever, together with any interest, fines
and any penalties, additions to tax or additional amounts incurred or accrued
under applicable federal, state, local or foreign tax law or assessed, charged
or imposed by any Authority, domestic or foreign, provided that any interest,
penalties, additions to tax or additional amounts that relate to Taxes for any
taxable period (including any portion of any taxable period ending on or before
the Closing Date) shall be deemed to be Taxes for such period, regardless of
when such items are incurred, accrued, assessed or charged.
(b) Member B has duly and timely filed (and prior to the Closing Date
will duly and timely file) true, correct and complete Tax returns, reports or
estimates, all prepared in accordance with applicable Laws, for all years and
periods (and portions thereof), for all jurisdictions (whether federal, state,
local or foreign) in which any such returns, reports or estimates were due, and
for all such returns, reports and estimates which are required to be filed by
any applicable Law on or prior to the Closing Date. All Taxes shown as due and
payable on such returns, reports and estimates have been paid (or will be paid
prior to the Closing), and there is no current liability for any Taxes due and
payable in connection with any such returns. There are no existing liens for
Taxes upon any of Member B's assets.
(c) Member B has (i) withheld all required amounts from its employees,
agents, contractors and nonresidents and remitted such amounts to the proper
Authorities; (ii) paid all employer contributions and premiums; and (iii) filed
all federal, state, local and foreign returns and reports with respect to
employee income Tax withholding, and social security and unemployment Taxes and
premiums, all in compliance with the withholding provisions of the Code, or any
prior provision of the Code and other applicable Laws.
(d) Other than as provided within the Documents, Member B's assets
consist solely of the Member B Interest.
(e) Member B does not engage (and has not previously engaged) in a
trade or business within the meaning of the Code, other than that of owning the
Member B Interest and the Business.
-9-
<PAGE>
(f) Member B is not a foreign person within the meaning of Code Section
1445.
(g) Member B is and always has been taxable as a corporation for
federal income tax purposes.
(h) Neither the Code nor any other provision of Law requires Purchaser
to withhold any portion of the Purchase Price.
(i) Other than as provided within the Documents, Member B is not a
party to any joint venture, partnership or other arrangement that could be
treated as a partnership for federal income Tax purposes.
(j) No federal, state, local or foreign Tax audits or other
administrative proceedings, discussions or court proceedings are presently
pending with regard to any Taxes or Tax returns of Member B and no additional
issues are being asserted against Member B in connection with any existing
audits of Member B, other than any such items which relate to the Business or
the Company.
(k) Other than as provided within the Documents, Member B has not
entered into any agreement relating to Taxes which affects any taxable year
ending after the Closing Date.
(l) Member B has not agreed to and it is not required to make any
adjustment by reason of a change in accounting methods that affects any taxable
year ending after the Closing Date, other than any such adjustment made by the
Company. Neither the IRS nor any other Authority has proposed any such
adjustment or change in accounting methods that affects any taxable year ending
after the Closing Date. Member B has no application pending with any taxing
authority requesting permission for any changes in accounting methods that
relate to its business or operations and that affects any taxable year ending
after the Closing Date, other than any such application made by the Company.
(m) Member B has not consented to the application of Code section
341(f).
(n) There is no contract, agreement, plan or arrangement covering any
employee or former employee of Member B that, individually or collectively,
could give rise to the payment by Member B of any amount that would not be
deductible by reason of Code section 280G.
III.12 Real Property. Except as may be contemplated by the Documents,
-------------
Member B has no title to or interests in any real property.
III.13 Consents. Except for filings pursuant to the HSR Act, no
--------
consent, approval, order or authorization of, or registration, declaration or
filing with, any Authority or any other Person is required to be obtained or
made by the Seller, GESFG or Member B in connection with the execution and
delivery of this Agreement or the performance by the Seller of its obligations
hereunder which has not been obtained.
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<PAGE>
III.14 Broker's or Consultant's Fees. Seller represents and warrants
-----------------------------
that it has dealt with no broker, finder or consultant in connection with any of
the transactions contemplated by this Agreement, and, to the Seller's Knowledge,
no Person is entitled to any commission, broker's or finder's fee in connection
with the sale of the Shares to Purchaser.
III.15 Banking Arrangements. Member B has no banking, borrowing or
--------------------
depository relationship, or accounts or deposits of funds.
III.16 Powers of Attorney. No Person holds any power of attorney from
------------------
Member B.
III.17 Loans. There are no loans (including, without limitation,
-----
principal, interest and fees) due and owing to Member B from Seller or any of
Member B's Affiliates, employees, officers or directors.
ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF PURCHASER
-------------------------------------------
As an inducement to Seller to enter into and perform their obligations
under this Agreement, and in consideration of the covenants of Seller contained
herein, Purchaser represents and warrants to Seller as of the date hereof and as
of the Closing Date (which representations and warranties shall survive the
Closing regardless of what examinations, inspections, audits and other
investigations Seller has heretofore made, or may hereafter make, with respect
to such representations and warranties) as follows:
IV.1 Corporate Status. Purchaser is a corporation duly organized,
----------------
validly existing and in good standing under the laws of the State of Nevada.
IV.2 Due Authorization. The execution and delivery by Purchaser of this
-----------------
Agreement, and the performance by Purchaser of its obligations hereunder, have
been duly and validly authorized and approved by all necessary corporate action
on the part of Purchaser.
IV.3 Authority of Purchaser. Purchaser has the corporate power and
----------------------
authority to execute and deliver this Agreement and to perform its obligations
hereunder. The execution, delivery and performance of this Agreement have been
duly authorized by all necessary action on the Purchaser's part and neither the
execution and delivery thereof, nor the consummation of the transactions
contemplated thereby, nor compliance by it with any of the terms and provisions
thereof requires or will require any approval of members or managers of, or
approval or consent of any trustee or holders of any indebtedness or obligations
of Purchaser, other than such consents and approvals as have been obtained and
are in full force and effect. Neither the execution or delivery of this
Agreement by Purchaser nor the performance by Purchaser of its obligations under
this Agreement will conflict with or result in a breach of any of the terms or
provisions of, or constitute a default under, any contract, lease, license,
franchise, permit, indenture, mortgage, deed of trust, note agreement or other
agreement or instrument to which Purchaser is a party or is bound, its articles
of incorporation, by-laws or any applicable Law or Order to which Purchaser is a
party or by which Purchaser is bound.
-11-
<PAGE>
IV.4 Enforceability. This Agreement has been duly executed and
--------------
delivered by Purchaser and (assuming the due authorization, execution and
delivery by Seller) constitutes its legal, valid and binding obligation
enforceable against Purchaser in accordance with its terms, subject to
bankruptcy, insolvency, reorganization and other laws affecting creditors'
rights generally and by principles of equity (whether in a proceeding at law or
in equity).
IV.5 Consents. Except for filings pursuant to the HSR Act or as
--------
otherwise contemplated by this Agreement, no consent, approval, Order or
authorization of, or registration, declaration or filing with, any Authority or
any other Person is required to be obtained or made by Purchaser in connection
with its execution and delivery of this Agreement or the performance by it of
its obligations hereunder.
IV.6 Broker's or Consultant's Fees. Purchaser represents and warrants
-----------------------------
that it has dealt with no broker, finder or consultant in connection with any of
the transactions contemplated by this Agreement, and, to its knowledge, no
Person is entitled to any commission or finder's fee in connection with the sale
of the Shares to Purchaser.
ARTICLE V
COVENANTS
---------
Seller and Purchaser covenant and agree that:
V.1 Required Filings. Prior to the Closing, Seller and Purchaser agree
----------------
to (a) promptly file, or cause to be promptly filed, with all appropriate
Authorities all notices, registrations, declarations, applications and other
documents as may be necessary as a result of the consummation of the
transactions contemplated hereby and (b) to diligently pursue all consents,
approvals and authorizations from such Authorities as may be necessary as a
result of the consummation of the transactions contemplated hereby. Seller and
Purchaser each covenant to (i) request early termination of the waiting period
required under the HSR Act, (ii) furnish to the other party such necessary or
appropriate information and reasonable assistance as such other party may
reasonably request in connection with its preparation of necessary filings and
submissions pursuant to the HSR Act and (iii) comply with a request for
additional information issued by any Authority as promptly as practical.
Purchaser shall pay the HSR Act filing fee.
V.2 Pre-Closing Taxes. Seller shall be liable for all Taxes imposed on
-----------------
or incurred by Member B or its assets for any taxable period ending on or before
the Closing Date, except to the extent provided otherwise in the Documents.
V.3 Tax Reports; Returns. Seller and Purchaser shall provide each other
--------------------
with such assistance as may reasonably be requested by the others in connection
with the preparation of any return or report of Taxes, any audit or other
examination by any taxing authority, or any judicial or administrative
proceedings relating to liabilities for Taxes. Seller and Purchaser will retain
for the full period of any statute of limitations and provide the others with
any records or information which may be relevant to such preparation, audit,
examination, proceeding or determination. Seller shall be responsible for
causing Member B to file all Tax returns and
-12-
<PAGE>
reports of Member B due on or prior to the Closing Date, which such returns and
reports shall be prepared and filed timely and on a basis consistent with
existing procedures for preparing such returns or reports and consistent with
prior practice with respect to the treatment of specific items on the returns or
reports.
V.4 Optional Section 338(h)(10) Elections.
-------------------------------------
(a) At the Purchaser's sole discretion and upon prior written notice
the Purchaser and the Seller shall make, or cause to be made, in an appropriate
and timely manner the elections provided for by Code section 338(h)(10) (and, to
the extent necessary to allow for such election under Code section 338(h)(10),
an election under Code section 338(g)) and any corresponding election under
state or local law with respect to the Purchaser's acquisition of the stock of
Member B ("Section 338 Elections").
---------------------
(b) Upon the Purchaser's delivery of written notice that the Section
338 Elections are to made pursuant to Section 5.4(a):
--------------
(i) The Purchaser and the Seller will cooperate with each other to
take all actions necessary or appropriate to effect and preserve the
Section 338 Elections, including, but not limited to, preparing a Form
8023-A (Corporate Qualified Stock Purchase Agreement) and any related and
comparable forms for state or local law ("Section 338 Election Forms").
--------------------------
(ii) The Purchaser shall have delivered to the Seller executed and
completed Section 338 Election Forms prepared in accordance with Law and
allocating the Modified Aggregate Deemed Sales Price (as defined in
Treasury Regulation section 1.338(h)(10)-1(f)(2)) among the assets of the
Member B in accordance with the applicable Regulations promulgated under
Code section 338. The Seller shall have such forms duly executed by the
appropriate persons and delivered to the Purchaser in a timely manner. The
Purchaser shall file in a timely manner, or cause to be filed in a timely
manner, all Section 338 Election Forms with the appropriate office of the
IRS.
(iii) The Purchaser and Seller agree to report, or cause to be
reported, the Purchaser's purchase of the stock of the Member B consistent
with the Section 338 Elections and shall take no position on any return, or
in any audit, examination, investigation, or other proceeding that is
inconsistent with such elections or the allocation of the Modified
Aggregate Deemed Sales Price among the Assets of Member B as set forth in
the Section 338 Election Forms.
(iv) The Purchaser agrees to indemnify Seller against any United
States federal and state Taxes incurred by Seller upon the sale of the
stock of Member B that Seller would not have incurred had Member B instead
sold its interest in the Company for the Purchase Price, and then
liquidated into Seller.
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<PAGE>
V.5 Further Assurance. At any time and from time to time from and after
-----------------
the Closing Date, Seller and Purchaser will, at the request and expense of the
other parties hereto, execute, acknowledge and deliver, or cause to be executed,
acknowledged and delivered, such instruments and other documents and perform or
cause to be performed such acts and provide such information, as may reasonably
be required to evidence or effectuate the sale, conveyance, transfer, assignment
and delivery to Purchaser of the Shares or for the performance by Seller or
Purchaser of any of their other respective obligations under this Agreement.
ARTICLE VI
CONDITIONS PRECEDENT TO PURCHASER'S OBLIGATIONS
-----------------------------------------------
6.1 Obligations to be Satisfied on or Prior to Closing Date. The
-------------------------------------------------------
obligation of Purchaser to purchase the Investor Interest under this Agreement
is subject to the satisfaction (or waiver by Purchaser), on or prior to the
Closing Date, of the following conditions:
(a) Accuracy of Representations and Warranties. Each of the
------------------------------------------
representations and warranties made by the Seller in this Agreement shall be
true and correct in all material respects on and as of the Closing Date as
though made on and as of such date except to the extent that any representation
or warranty is made herein as of a specified date, in which case such
representation or warranty shall be true and correct in all material respects
and in all respects as of such date.
(b) Compliance with Agreement. The Seller shall have performed or
-------------------------
complied in all material respects with the covenants, agreements and obligations
required by this Agreement to be performed or complied with by the Seller on or
prior to the Closing Date.
(c) HSR Act Waiting Period. All applicable waiting periods (and any
----------------------
extensions thereof) under the HSR Act shall have expired or otherwise been
terminated.
(d) Closing Documents. The Seller shall have delivered all reports,
-----------------
agreements, certificates, instruments, opinions and other documents required to
be delivered by the Seller on the Closing Date pursuant to Section 8.3.
-----------
ARTICLE VII
CONDITIONS PRECEDENT TO SELLER'S OBLIGATIONS
--------------------------------------------
7.1 Obligations to Be Satisfied on or Prior to Closing Date. The
-------------------------------------------------------
obligations of the Seller to sell the Investor Interest under this Agreement are
subject to the satisfaction (or waiver by the Seller), on or prior to the
Closing Date, of the following conditions:
(a) Accuracy of Representations and Warranties. Each of the
------------------------------------------
representations and warranties made by Purchaser in this Agreement shall be true
and correct in all material respects on the Closing Date as though made on and
as of such date, except to the
-14-
<PAGE>
extent that any representation or warranty is made herein as of a specified
date, in which case such representation or warranty shall be true and correct in
all material respects as of such date.
(b) Compliance with Agreement. The Purchaser shall have each
-------------------------
performed or complied in all material respects with the covenants, agreements
and obligations required by this Agreement to be performed or complied with by
it on or prior to the Closing Date.
(c) HSR Act Waiting Period. All applicable waiting periods (and any
----------------------
extensions thereof) under the HSR Act shall have expired or otherwise been
terminated.
(d) Closing Documents. Purchaser shall have delivered all reports,
-----------------
agreements, certificates, instruments, opinions and other documents required to
be delivered by it on the Closing Date pursuant to Section 8.4.
-----------
ARTICLE VIII
CLOSING
-------
8.1 Time and Place. The Closing shall take place at 10:00 a.m. (Chicago
--------------
time) on the Closing Date at the offices of Winston & Strawn, 35 West Wacker
Drive, Chicago, Illinois.
8.2 Closing Transactions. All documents and other instruments required
--------------------
to be delivered at the Closing shall be regarded as having been delivered
simultaneously, and no document or other instrument shall be regarded as having
been delivered until all have been delivered.
8.3 Deliveries by Seller to Purchaser. At the Closing, Seller shall
---------------------------------
deliver or cause to be delivered to Purchaser:
(a) certificates representing all of the Shares which such
certificates shall be either duly endorsed or accompanied by stock powers
duly endorsed;
(b) a certificate of the Secretary or Assistant Secretary of Member
B, dated as of the Closing Date, certifying as to (i) the certificate of
incorporation of Member B and (ii) the by-laws of Member B;
(c) certificate of good standing for Member B from the State of
Delaware;
(d) a certificate of the Attesting Secretary of Seller, dated as of
the Closing Date, certifying to (i) the articles of incorporation of
Seller; (ii) the by-laws of Seller; (iii) resolutions of the Board of
Directors of Seller and (iv) incumbency and signatures of the officers of
Seller executing this Agreement and any other certificate or document
delivered in connection herewith;
(e) certificate of good standing for Seller from the State of New
York;
-15-
<PAGE>
(f) a certificate of the Secretary or the Assistant Secretary of
GESFG, dated as of the Closing Date, certifying to (i) the certificate of
incorporation of GESFG, (ii) the by-laws of GESFG; (iii) resolutions of the
Board of Directors of GESFG and (iv) incumbency and signatures of the
officers of GESFG executing any certificate or document delivered in
connection with this Agreement;
(g) certificate of good standing for GESFG from the State of
Delaware;
(h) a withholding certificate, in the form of Exhibit A executed by
---------
GESFG;
(i) opinion, dated the Closing Date, of counsel to Seller addressed
to Purchaser;
(j) original minute book, stock ledger, corporate seal, books of
account, financial records and similar corporate records, of Member B, to
the extent such exist;
(k) evidence of resignations of all directors and officers of Member
B effective on the Closing Date; and
(l) such other instruments and documents as are: (i) required by any
other provisions of this Agreement to be delivered on the Closing Date by
Seller to Purchaser; or (ii) reasonably necessary, in the opinion of
Purchaser, to effect the performance of this Agreement by Seller.
8.4 Deliveries by Purchaser to Seller. At the Closing, Purchaser shall
---------------------------------
deliver or cause to be delivered to Seller:
(a) the Purchase Price in accordance with Section 2.2;
-----------
(b) a certificate of the Secretary or an Assistant Secretary of
Purchaser, dated as of the Closing Date, certifying to (i) the articles of
incorporation of Purchaser, (ii) the by-laws of Purchaser; (iii)
resolutions of the Board of Directors of Purchaser; and (iv) incumbency and
signatures of the officers of Purchaser executing this Agreement and any
other certificate or document delivered in connection herewith;
(c) certificate of good standing for Purchaser from the State of
Nevada;
(d) written consents duly executed by Purchaser and dated the Closing
Date electing eligible persons as directors of Member B and written
consents of such directors appointing eligible persons as officers of
Member B;
(e) such other instruments and documents as are: (i) required by any
other provisions of this Agreement to be delivered on the Closing Date by
Purchaser to Seller;
-16-
<PAGE>
or (ii) reasonably necessary, in the opinion of Seller, to effect the
performance of this Agreement by Purchaser; and
(f) confirmation by Purchaser and A Members that neither Seller nor
Member B nor any Affiliate is in default under any Document as of the
Closing Date.
ARTICLE IX
INDEMNIFICATION
---------------
9.1 Indemnification by Seller. Seller agrees to indemnify, defend,
-------------------------
hold harmless and waive any claim for contribution against Purchaser, Member B
and all of their officers, directors, shareholders, Affiliates, employees and
agents (the "Purchaser Indemnified Persons") after the Closing from and against
-----------------------------
any Adverse Consequence arising out of or resulting from:
(a) the untruth, inaccuracy or incompleteness of any representation
or warranty of Seller contained in this Agreement or Schedules hereto (or
in any document, writing, certificate, data or financial statements
delivered by Seller under this Agreement) (each a "Purchaser Warranty
------------------
Claim") or the failure by Seller to perform any of its covenants or
-----
obligations hereunder;
(b) any brokers' commissions, finders' fees or other like payments
incurred or alleged to have been incurred by Seller or Member B in
connection with the sale of the Investor Interest or the consummation of
the transactions contemplated by this Agreement;
(c) except as otherwise provided in the Documents, all Taxes imposed
on, payable by or attributable to Member B or its assets for taxable
periods ending on or before the Closing Date, and for its allocable share
of Taxes for any period that begins prior to the Closing Date and ends
after the Closing Date (including, in each case, any payment due from
Member B under any agreement sharing or apportioning any such Taxes).
Seller's allocable share of Taxes determined by reference to income,
capital gains, gross income, gross receipts, sales, net profits, windfall
profits and similar gains, shall be determined based on the date on which
such items accrued. For all other Taxes, Seller's allocable share shall be
determined pro rata based on the number of days in the taxable period for
which each party is liable for Taxes hereunder; and
(d) All Taxes imposed on, payable by or attributable to Member B or
its assets that do not relate to the Business (including any consolidated
return joint liability for federal income taxes under Treasury Regulation
section 1.1502-6), except to the extent attributable to operations in
respect of the Company or actions taken by Member B after the Closing Date.
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<PAGE>
9.2 Indemnification by Purchaser. Purchaser agrees to indemnify, defend
----------------------------
and hold harmless Seller after the Closing from and against any Adverse
Consequences arising out of or resulting from:
(a) the untruth, inaccuracy or incompleteness as of the date hereof
or on the Closing Date of any representation or warranty of Purchaser
contained in this Agreement (or in any document, writing or certificate
delivered by Purchaser under this Agreement) (each a "Seller Warranty
---------------
Claim") or the failure by Purchaser to perform any of its covenants or
-----
obligations hereunder;
(b) any claim, including any liability or obligation of Purchaser or
Member B to be satisfied or performed on or after the Closing Date;
(c) any act, condition or event with respect to the Investor Interest
arising or relating to the period on and after the Closing Date, including,
without limitation, any breach or default by Seller or Member B of its
obligations pursuant to the Documents on and after the Closing Date;
(d) except as otherwise provided in the Documents, all Taxes imposed
on, payable by or attributable to Member B or its assets for taxable
periods beginning on or after the Closing Date, and for its allocable share
of Taxes for any period that begins prior to the Closing Date and ends
after the Closing Date (including, in each case, any payment due from
Member B under any agreement sharing or apportioning any such Taxes).
Purchaser's allocable share of Taxes determined by reference to income,
capital gains, gross income, gross receipts, sales, net profits, windfall
profits and similar gains, shall be determined based on the date on which
such items accrued. For all other Taxes, Purchaser's allocable share shall
be determined pro rata based on the number of days in the taxable period
for which each party is liable for Taxes hereunder; and
(e) to the extent required under the Documents with respect to Prior
Claims.
9.3 Procedure for Indemnification. If any Person shall claim
-----------------------------
indemnification (the "Indemnified Party") hereunder for any claim other than a
-----------------
third party claim, the Indemnified Party shall promptly give written notice to
the other party from whom indemnification is sought (the "Indemnifying Party")
------------------
of the nature and amount of the claim. If an Indemnified Party shall claim
indemnification hereunder arising from any claim or demand of a third party, the
Indemnified Party shall promptly give written notice (a "Third-Party Notice") to
------------------
the Indemnifying Party of the basis for such claim or demand, setting forth the
nature of the claim or demand in detail. The Indemnifying Party shall have the
right to compromise or, if appropriate, defend at its own cost and through
counsel of its own choosing, any claim or demand set forth in a Third-Party
Notice giving rise to such claim for indemnification. In the event the
Indemnifying Party undertakes to compromise or defend any such claim or
demand, it shall promptly (and in any event, no later than fifteen (15) days
after receipt of the Third-Party Notice) notify the Indemnified Party in writing
of its intention to do so. The Indemnified Party shall fully cooperate with the
Indemnifying Party and its counsel in the defense or compromise of such
-18-
<PAGE>
claim or demand. After the assumption of the defense by the Indemnifying Party,
the Indemnified Party shall not be liable for any legal or other expenses
subsequently incurred by the Indemnifying Party, in connection with such
defense, but the Indemnified Party may participate in such defense at its own
expense. No settlement of a third party claim or demand defended by the
Indemnifying Party shall be made without the written consent of the Indemnified
Party, such consent not to be unreasonably withheld. The Indemnifying Party
shall not, except with the written consent of the Indemnified Party, consent to
the entry of a judgment or settlement which does not include as an unconditional
term thereof, the giving by the claimant or plaintiff to the Indemnified Party
of an unconditional release from all liability in respect of such third party
claim or demand. With respect to claims arising prior to the date hereof, if the
Documents provide other than as provided in this Section 9.3, then the
-----------
Documents shall control the procedure for indemnification.
9.4 Payment. Except for third-party claims being defended in good faith
-------
by the Indemnifying Party in accordance with Section 9.3, the Indemnifying Party
-----------
shall satisfy its obligations hereunder within fifteen (15) days after receipt
of notice of a claim. Any amount not paid to the Indemnified Party by such date
shall bear interest at a rate equal to Overdue Rate from the date due until the
date paid.
ARTICLE X
MISCELLANEOUS PROVISIONS
------------------------
10.1 Post-Closing Deliveries. After the Closing, any monies, checks,
-----------------------
instruments, invoices, bills, receipts, notices, mail and other communications
received by one party but directed toward or due to another shall be promptly
delivered to the other party. Seller shall cooperate with Purchaser after the
Closing to ensure the orderly transition of the operation of the Business from
Seller to Purchaser and to minimize any disruption in the business of Purchaser
that might result from the transactions contemplated hereby.
10.2 Notices. All notices or other communications required or permitted
-------
by this Agreement shall be in writing and shall be deemed to have been duly
received (a) if given by telecopier, when transmitted and the appropriate
telephonic confirmation received if transmitted on a business day and during
normal business hours of the recipient, and otherwise on the next business day
following transmission, (b) if given by certified or registered mail, return
receipt requested, postage prepaid, three business days after being deposited in
the U.S. mails and (c) if given by courier or other means, when received or
personally delivered, and, in any such case, addressed as follows:
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<PAGE>
(i) if to Purchaser:
Sierra Pacific Power Company
6100 Neil Road
Reno, Nevada 89520
Attention: Richard Atkinson
Facsimile: (702) 834-3815
with a copy to:
Winston & Strawn
35 West Wacker Drive
Chicago, Illinois 60601
Attention: John C. Lorentzen
Facsimile: (312) 558-5700
(ii) if to Seller:
General Electric Capital Corporation
Structured Finance Group
120 Long Ridge Road, 3rd Floor
Stamford, Connecticut 06927
Attention: Compliance Officer, GPSF-B Inc. 760-1
Facsimile: (203) 961-2017
or to such other addresses as may be specified by any such Person to the other
Person pursuant to notice given by such Person in accordance with the provisions
of this Section 10.2.
------------
10.3 Assignment. No party may assign or transfer any or all of its
----------
rights or obligations under this Agreement without the prior written approval of
all the other parties; provided, however, that Purchaser may assign or transfer
-------- -------
all or less than all of its rights and obligations under this Agreement to any
Person.
10.4 Benefit of the Agreement. This Agreement shall be binding upon and
------------------------
inure to the benefit of the parties hereto and their respective successors and
permitted assigns. This Agreement shall not be construed so as to confer any
right or benefit upon any Person, other than the parties hereto and their
respective successors and permitted assigns.
10.5 Exhibits and Schedules. The Exhibits and Schedules hereto shall be
----------------------
construed with and as an integral part of this Agreement to the same effect as
if the contents thereof had been set forth verbatim herein.
-20-
<PAGE>
10.6 Headings. The headings used in this Agreement are for convenience
--------
of reference only and shall not be deemed to limit, characterize or in any way
affect the interpretation of any provision of this Agreement.
10.7 Entire Agreement. Except as otherwise specifically provided herein,
----------------
this Agreement contains the entire agreement and understanding of the parties
with respect to the subject matter hereof, and no other representations,
promises, agreements or understandings regarding the subject matter hereof shall
be of any force or effect unless in writing, executed by the party to be bound
thereby and dated on or after the date hereof.
10.8 Modifications and Waivers. No change, modification or waiver of
-------------------------
any provision of this Agreement shall be valid or binding unless it is in
writing, dated subsequent to the date hereof and signed by Purchaser and Seller.
No waiver of any breach, term or condition of this Agreement by any party shall
constitute a subsequent waiver of the same or any other breach, term or
condition.
10.9 Counterparts. This Agreement may be executed in counterparts, each
------------
of which shall be deemed an original, but all of which together shall constitute
one and the same instrument.
10.10 Severability. In case any one or more of the provisions contained
------------
herein for any reason shall be held to be invalid, illegal or unenforceable in
any respect, such invalidity, illegality or unenforceability shall not affect
any other provision of this Agreement, but this Agreement shall be construed as
if such invalid, illegal or unenforceable provision or provisions had never been
contained herein.
10.11 GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED
-------------
IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.
10.12 Expenses. Except as otherwise expressly provided herein,
--------
Purchaser shall pay all of both the Purchaser's and the Seller's costs and
expenses incurred or to be incurred in negotiating and preparing this Agreement
and in closing and carrying out the transactions contemplated by this Agreement
("Agreement Expenses"); provided, however, that the Seller shall pay all
------------------ -------- -------
Agreement Expenses it incurs in excess of $40,000.
10.13 Tax Consequences. Except as set forth herein, Purchaser shall
----------------
have no liability for the tax consequences to Seller, and Seller shall have no
liability for the tax consequences to Purchaser as a result of the purchase of
the Investor Interest as contemplated hereby.
-21-
<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed this Purchase and Sale
and Assignment and Assumption Agreement as of the date first written above.
PURCHASER: SIERRA PACIFIC POWER COMPANY
By:_____________________________________
Title:__________________________________
SELLER: GENERAL ELECTRIC CAPITAL CORPORATION
By:_____________________________________
Title:__________________________________
-22-
<PAGE>
EXHIBIT A
FORM OF WITHHOLDING CERTIFICATE
I, _________________, hereby certify as to the following on behalf of GE
Capital Services Structured Finance Group, Inc. (the "Transferor"):
1. Transferor is not a foreign corporation, foreign partnership, foreign
trust, or foreign estate (as those terms are defined in the Internal Revenue
Code and Income Tax Regulations);
2. Transferor's U.S. employer identification number is 08-1154651; and
3. Transferor's office address is 120 Long Ridge Road, Stamford,
Connecticut 06927.
The undersigned understands that this certification may be disclosed to the
Internal Revenue Service by the transferee and that any false statement
contained herein could be punished by fine, imprisonment, or both.
Under penalties of perjury, I declare that I have examined this
certification and to the best of my knowledge and belief it is true, correct,
and complete, and I further declare that I have authority to sign this document
on behalf of Transferor.
GE CAPITAL SERVICES STRUCTURED
FINANCE GROUP, INC.
By: ____________________________________
Printed Name: ___________________________
Its:_____________________________________
_______________________________
Date
-23-
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE COMPANY'S
FINANCIAL RECORDS AND IS QUALFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,677,042
<OTHER-PROPERTY-AND-INVEST> 34,022
<TOTAL-CURRENT-ASSETS> 158,045
<TOTAL-DEFERRED-CHARGES> 142,711
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,011,820
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 0
<TOTAL-COMMON-STOCKHOLDERS-EQ> 661,367
48,500
73,115
<LONG-TERM-DEBT-NET> 606,450
<SHORT-TERM-NOTES> 105,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 30,473
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 486,915
<TOT-CAPITALIZATION-AND-LIAB> 2,011,820
<GROSS-OPERATING-REVENUE> 734,332
<INCOME-TAX-EXPENSE> 43,550
<OTHER-OPERATING-EXPENSES> 564,588
<TOTAL-OPERATING-EXPENSES> 608,138
<OPERATING-INCOME-LOSS> 126,194
<OTHER-INCOME-NET> 4,132
<INCOME-BEFORE-INTEREST-EXPEN> 130,326
<TOTAL-INTEREST-EXPENSE> 40,135
<NET-INCOME> 90,191
9,630
<EARNINGS-AVAILABLE-FOR-COMM> 80,561
<COMMON-STOCK-DIVIDENDS> 76,000
<TOTAL-INTEREST-ON-BONDS> 35,933
<CASH-FLOW-OPERATIONS> 153,191
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1>SIERRA PACIFIC POWER COMPANY IS A WHOLLY OWNED SUBSIDIARY OF SIERRA PACIFIC
RESOURCES AND AS SUCH ITS COMMON STOCK IS NOT PUBLICLY TRADED. SPPC DOES NOT
REPORT EPPS INFORMATION.
</FN>
</TABLE>
