<PAGE>
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 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, 1996 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 offices) (Zip Code)
(702) 689-5400
(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:
<TABLE>
<CAPTION>
<S> <C>
Preferred Stock: Series A, $2.44 Dividend, $50 par value
---------------
(Title of Class) Series B, $2.36 Dividend, $50 par value
Series C, $3.90 Dividend, $50 par value
Sierra Pacific Power Capital Trust I, $2.15 Dividend, $25 stated value
</TABLE>
Indicate by check mark whether the 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
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
---
State the aggregate market value of the voting stock held by non-affiliates. As
of March 20, 1997: None.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.
Class Outstanding at March 20,1997
Common Stock, $3.75 par value 1,000 Shares
================================================================================
<PAGE>
SIERRA PACIFIC POWER COMPANY
1996 ANNUAL REPORT FORM 10-K
CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
EXPLANATION OF ABBREVIATIONS USED......................................................... 3
GLOSSARY OF UTILITY TERMS USED............................................................ 5
PART I.
- ------
ITEM 1. BUSINESS
THE COMPANY............................................................. 8
FINANCIAL INFORMATION RELATING TO BUSINESS SEGMENTS..................... 9
BUSINESS OUTLOOK AND OVERVIEW........................................... 10
GENERAL ELECTRIC INDUSTRY TRENDS........................................ 11
MERGER TERMINATION...................................................... 11
ELECTRIC BUSINESS....................................................... 12
NATURAL GAS BUSINESS.................................................... 25
WATER BUSINESS.......................................................... 29
CONSTRUCTION PROGRAM.................................................... 33
GENERAL REGULATION...................................................... 34
RATE PROCEEDINGS
NEVADA MATTERS..................................................... 35
ENVIRONMENT............................................................. 36
GENERAL
FACILITIES......................................................... 39
LEASEHOLDS......................................................... 39
FRANCHISES......................................................... 40
RESEARCH, DEVELOPMENT AND DEMONSTRATION............................ 41
ITEM 2. PROPERTIES.................................................................... 42
ITEM 3. LEGAL PROCEEDINGS............................................................. 42
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........................... 42
PART II.
- -------
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK
AND RELATED STOCKHOLDER MATTERS.......................................... 43
ITEM 6. SELECTED FINANCIAL DATA....................................................... 44
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS...................................... 45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................... 54
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE................................... 85
PART III.
- --------
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS OF THE REGISTRANT.................................... 86
ITEM 11. EXECUTIVE COMPENSATION........................................................ 92
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT......................................... 98
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................................ 100
PART IV.
- -------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K.................................................. 102
</TABLE>
<PAGE>
SIERRA PACIFIC POWER COMPANY
EXPLANATION OF ABBREVIATIONS USED IN
1996 FORM 10-K
ABBREVIATION DEFINITION
- --------------------- ------------------------------------------
AFUDC Allowance for Funds Used During Construction
ANG Alberta Natural Gas
APB Accounting Principles Board
ARA Attrition Rate Adjustment
Black Butte Black Butte Coal Company
BLM Bureau of Land Management
California Commission California Public Utilities Commission
Canyon Canyon Coal Company
CT Combustion Turbine
CWIP Construction Work in Progress
DOE U.S. Department of Energy
ECAC Energy Cost Adjustment Clause
EIR/S Environmental Impact Report/Statement
EPA U.S. Environmental Protection Agency
EPRI Electric Power Research Institute
ERAM Energy Revenue Adjustment Mechanism
FERC Federal Energy Regulatory Commission
GECC General Electric Capital Corporation
GRI Gas Research Institute
HTNF Humboldt-Toiyabe National Forest
Idaho Power Idaho Power Company
INDEGO Independent Transmission Grid Operator
INGR Incentive Natural Gas Sales Rate
ISO Independent System Operator
ITC Investment Tax Credits
KWH Kilowatt-hour
KV Kilovolt
LDC Local Distribution Company
LNG Liquid Natural Gas
MMBtu Million British Thermal Units
MTN Medium-Term Note
MW Megawatt
MWH Megawatt-hour
NDOW Nevada Department of Wildlife
NEPA National Environmental Protection Act
Nevada Commission Public Service Commission of Nevada
Northwest Northwest Pipeline Corporation
OASIS FERC Mandated Electronic Bulletin Board
Paiute Paiute Pipeline Company
Pinon Pinon Pine Power Project
PG&E Pacific Gas and Electric Company
PGT Pacific Gas Transmission
PPC Pinon Pine Corp.
PPIC Pinon Pine Investment Co.
PRP Potentially Responsible Party
PSA Preliminary Settlement Agreement
PX Power Exchange
QF Qualifying Facility
Resources West Resources West Energy Company
3
<PAGE>
SIERRA PACIFIC POWER COMPANY
EXPLANATION OF ABBREVIATIONS USED IN
1996 FORM 10-K - CONTINUED
ABBREVIATION DEFINITION
- --------------------- ------------------------------------------
SDWA Safe Drinking Water Act
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
SPR Sierra Pacific Resources
SWDC Sierra Water Development Company
SWOASIS Southwest Oasis Electronic Bulletin Board
SWTR Surface Water Treatment Rule
TCID Truckee-Carson Irrigation District
TDPUD Truckee Donner Public Utility District
The Company Sierra Pacific Power Company
The Trust Sierra Pacific Power Capital I
The LLC Pinon Pine Co., LLC
TGPC Tuscarora Gas Pipeline Company
TGTC Tuscarora Gas Transmission Company
TRA Tax Reform Act of 1986
TransCanada TransCanada Pipelines USA, Limited
Tri-State Tri-State Generation & Transmission Association
Utah Power Utah Power & Light Company (PacifiCorp Division)
WWP The Washington Water Power Company
4
<PAGE>
SIERRA PACIFIC POWER COMPANY
GLOSSARY OF UTILITY TERMS USED IN
1996 FORM 10-K
Avoided Costs
- -------------
The costs a utility would otherwise incur to generate or purchase power if not
acquired from another source.
Capacity
- --------
The load for which a generating unit, or station, or other electrical
apparatus is rated either by the user or by the manufacturer.
Decatherm
- ---------
A unit used to measure the amount of heat value in gas. A decatherm is equal
to one million British thermal units (BTUs). One BTU equals the amount of
heat required to raise the temperature of one pound of water one degree
Fahrenheit.
Demand
- ------
The amount of electricity delivered to consumers at any instant or as averaged
over a period of time.
Demand-side
- -----------
A term of reference regarding issues originating with consumer demand.
Gasifier
- --------
Large enclosed vessel in which coal is heated under pressure at high
temperatures to produce a vaporous gas which can be burned in a combustion
turbine.
Geothermal generation
- ---------------------
The process by which hot water or natural steam from the earth is used to
produce electrical energy directly for steam-turbine thermal generation.
Kilovolt
- --------
One thousand volts, which is a measure of electrical pressure which forces
electric current through a wire.
Kilowatt-hour
- -------------
A measure of the amount of electricity sold or consumed. It is the basic
customer billing unit, and is the mathematical product of demand and time.
Burning a 100-watt light bulb for ten hours is equal to one kilowatt-hour.
Line extension
- --------------
An extension of an electric power line from the nearest point of transmission
to a required point of delivery. For gas and water systems, the extension
of mains or pipes to accommodate new service.
Load
- ----
In power production, it is the megawatt demand or megawatts being served at
any given moment.
5
<PAGE>
SIERRA PACIFIC POWER COMPANY
GLOSSARY OF UTILITY TERMS USED IN
1996 FORM 10-K - CONTINUED
Megawatt
- --------
A unit equal to one million watts, which measure the instantaneous amount of
electricity used in electric equipment.
Megawatt-hour
- -------------
A unit of measure equal to 1,000 kilowatt-hours. Also equal to the amount of
electricity consumed in a one hour period by a one megawatt load.
Negotiated Settlement
- ---------------------
With the passage of Public Law 101-618 in 1990, the United States, California
and Nevada, Pyramid Lake Paiute Tribe and the Company took a major step
toward an overall settlement of Truckee River issues. The Settlement
quiets bi-state claims to the River's water, resolves many years of
litigation, provides environmental and Tribal benefits and more than
triples the drought storage available to Sierra's customers.
Non-utility generator
- ---------------------
Producers of electric generation who are not considered electric utilities.
Peak or peak load
- -----------------
The maximum demand for electric power that determines the generating capacity
required, or the maximum load consumed over a given period of time (usually
one hour). There are daily, monthly and annual peak loads, or peak demand
(usually measured in kilowatt hours or megawatt hours).
Qualifying facility
- -------------------
Independent, non-utility power generators that meet certain requirements of
the Public Utility Regulatory Policies Act.
PCB
- ---
Polychlorinated Biphenyl -- A carcinogenic chemical found in electrical
equipment.
Rate base
- ---------
The net investment in facilities, equipment, other property, and programs a
utility has constructed, purchased, or pursued in order to provide utility
service to its customers, and on which a return is allowed.
Revenue Requirement
- -------------------
The sum total of the revenues required to pay all operating and capital costs
of providing service.
6
<PAGE>
SIERRA PACIFIC POWER COMPANY
GLOSSARY OF UTILITY TERMS USED IN
1996 FORM 10-K - CONTINUED
Spot market
- -----------
Electric power, fuel or gas purchased on an as-needed and as-available basis
rather than under a firm contract.
Syngas
- ------
Synthetic natural gas, which is the result of the conversion of other gases,
solid hydrocarbons (such as coal) or liquids to form a gaseous fuel similar
in performance to that of natural gas.
Wheeling
- --------
The use of a utility's electric transmission system by any party other than
the party who owns it.
7
<PAGE>
PART I
ITEM 1. BUSINESS
THE COMPANY
-----------
Sierra Pacific Power Company, hereinafter known as the Company or SPPC, is
a Nevada corporation which was 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 three primary subsidiaries: Pinon Pine Corp. (PPC), Pinon
Pine Investment Co. (PPIC) and Sierra Pacific Power Capital I (the Trust). The
Company, through PPC and PPIC, owns a 38% interest in the Pinon Pine Co., LLC
(The LLC) with a subsidiary of General Electric Capital Corporation owning the
remaining 62%.
The Company is a public utility primarily engaged in the generation,
purchase, transmission, distribution and sale of electric energy. It provides
electricity to approximately 278,000 customers in a 50,000 square mile service
area including western, central and northeastern parts of Nevada, including the
cities of Reno, Sparks, Carson City and Elko and a portion of eastern
California, including the Lake Tahoe area. In 1996 electric revenue was 82% of
total revenue.
The Company used diverse resources to meet its 1996 electric energy
requirements, including gas and oil generation (34.2%), coal generation (20.2%),
hydroelectric generation (.6%), and purchased power (45.0%). The Company has no
ownership interest in, nor does it operate, any nuclear generating units.
The Company also provides natural gas in Nevada to approximately 95,000
customers in an area of about 600 square miles in Reno/Sparks and environs. It
supplies water service in Nevada to about 63,000 customers in the Reno/Sparks
metropolitan area. Natural gas revenues were 11% and water revenues were 7% of
total revenues.
In 1996 the Company's electric customers grew 2.8%; its natural gas
customers increased by 4.4%; and its water customers were up 2.7%. Many factors
account for this growth, not the least of which are favorable business and tax
climates.
The Company's workforce numbered 1,491 regular employees as of December 31,
1996, down 2.3% from 1995. Of that number, 21 were considered part-time. In
addition, the Company had 44 temporary employees. The Company's current
contract with the International Brotherhood of Electrical Workers, which
represents 61% of the workforce, is in effect until December 31, 1997. The
three-year contract provides for a 2.5% general wage increase for all bargaining
unit employees beginning January 1, 1995, with 3% increases in both 1996 and
1997. Negotiations on the renewal of the contract will begin in 1997. Nevada is
a "right-to-work" state.
8
<PAGE>
FINANCIAL INFORMATION RELATING TO
---------------------------------
BUSINESS SEGMENTS
-----------------
(DOLLARS IN THOUSANDS)
----------------------
<TABLE>
<CAPTION>
1996 1995 1994
----------------- ---------------- -----------------
<S> <C> <C> <C>
Operating Revenues
Electric $ 507,004 (82%) $ 491,419 (82%) $ 498,680 (83%)
Gas 67,376 (11%) 62,572 (11%) 65,174 (11%)
Water 45,344 (7%) 43,793 (7%) 39,339 (6%)
--------------- -------------- --------------
$ 619,724 (100%) $ 597,784 (100%) $ 603,193 (100%)
=============== ============== ==============
Operating Income
Electric $ 86,428 (81%) $ 87,825 (86%) $ 81,641 (85%)
Gas 11,035 (10%) 5,041 (5%) 5,806 (6%)
Water 9,545 (9%) 8,945 (9%) 8,536 (9%)
--------------- -------------- --------------
$ 107,008 (100%) $ 101,811 (100%) $ 95,983 (100%)
=============== ============== ==============
Identifiable Assets
Electric $1,324,579 (7%) $1,222,518 (7%) $1,144,490 (78%)
Gas 117,697 (7%) 109,872 (7%) 106,951 (7%)
Water 268,813 (16%) 246,031 (16%) 223,248 (15%)
--------------- -------------- --------------
$1,711,089 (100%) $1,578,421(100%) $1,474,689(100%)
=============== ============== ==============
</TABLE>
For a discussion of results of operations refer to Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations.
9
<PAGE>
BUSINESS OUTLOOK AND OVERVIEW (1)
-----------------------------
The economy in the Company's service area is growing and benefits from
Nevada's freeport law that promotes the warehouse industry and the processing of
goods in transit, primarily to markets in California. Nevada has no corporate,
personal, unitary, inventory or income taxes. Permanent residents are attracted
to the quality of life found in the area and the absence of personal income tax.
Additionally, Reno/Sparks and Lake Tahoe provide leisure-time diversions,
including skiing, golf, water sports, camping, casino gaming and big name
entertainment that appeal to residents and tourists alike. The combination of
tax advantages, supportive government, location and lifestyle make Nevada an
attractive site for businesses.
Also contributing to the growth in the service area are Nevada's mineral
resources, which support a mining industry that continues to contribute
significantly to the area's economy and remains the Company's second largest
source of revenue after residential sales. In 1996, mining represented 15% of
the Company's electric revenue and 24.5% of total electric megawatt-hour (MWH)
sales. The outlook for 1997 forecasts that electric sales to mines may account
for 27% of total retail electric MWH sales and 21% of total electric revenue.
The Company's electric, natural gas and water business segments are all, to
varying degrees, dependent on weather conditions. Extreme or prolonged
variations from historical weather patterns could adversely affect sales in one
or more of these business segments.
(1) WHEN USED ANYWHERE IN THIS FORM 10-K AND IN FUTURE FILINGS BY THE COMPANY
WITH THE SECURITIES AND EXCHANGE COMMISSION, IN THE COMPANY'S PRESS
RELEASES AND IN ORAL STATEMENTS MADE WITH THE APPROVAL OF AN AUTHORIZED
EXECUTIVE OFFICER, THE WORDS OR PHRASES "WILL LIKELY RESULT", "ARE
EXPECTED TO", "WILL CONTINUE", "IS ANTICIPATED", "ESTIMATED", "PROJECT",
OR "OUTLOOK" OR SIMILAR EXPRESSIONS ARE INTENDED TO IDENTIFY "FORWARD-
LOOKING STATEMENTS" WITHIN THE MEANING OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995. SUCH STATEMENTS ARE SUBJECT TO CERTAIN
RISKS AND UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER
MATERIALLY FROM HISTORICAL EARNINGS AND THOSE PRESENTLY ANTICIPATED OR
PROJECTED. THE COMPANY WISHES TO CAUTION READERS NOT TO PLACE UNDUE
RELIANCE ON ANY SUCH FORWARD-LOOKING STATEMENTS, WHICH SPEAK ONLY AS OF
THE DATE MADE. THE COMPANY WISHES TO ADVISE READERS THAT VARIOUS FACTORS
DESCRIBED IN THIS FORM 10-K COULD CAUSE THE COMPANY'S ACTUAL RESULTS FOR
FUTURE PERIODS TO DIFFER MATERIALLY FROM ANY OPINIONS OR STATEMENTS
EXPRESSED WITH RESPECT TO FUTURE PERIODS IN ANY CURRENT STATEMENTS. THE
COMPANY SPECIFICALLY DECLINES ANY OBLIGATION TO PUBLICLY RELEASE THE
RESULT OF ANY REVISIONS WHICH MAY BE MADE TO ANY FORWARD-LOOKING
STATEMENTS TO REFLECT EVENTS OR CIRCUMSTANCES AFTER THE DATE OF SUCH
STATEMENTS OR TO REFLECT THE OCCURRENCE OF ANTICIPATED OR UNANTICIPATED
EVENTS.
10
<PAGE>
GENERAL ELECTRIC INDUSTRY TRENDS
--------------------------------
There are many different views concerning the electric utility industry and
the changes it is experiencing now and will face in the future. Some changes
will be regulatory and others may be legislative.
To meet the challenges such changes bring to the industry, the Company has
down-sized and reorganized to cut costs, better serve its customers and prepare
for competition. The Company also has negotiated long-term contracts with six
of its largest mining customers.
Nevada electric prices were last increased in 1993, and were subsequently
reduced in March 1995, following suspension of deferred energy accounting rules.
Natural gas prices were last increased in April 1994, and the last increase in
water prices occurred in September 1994.
The Company currently has frozen its Nevada electric and natural gas rates
until December 31, 1999 and electric rates in California until December 31,
2000. A recent rate plan in Nevada also provides a 50/50 sharing between
customers and shareholders of electric and natural gas earnings in excess of a
12 percent return on equity. The plan also provides the opportunity for the
Company, subject to certain conditions, to apply such excess to buying down, or
buying out of, higher cost long-term fuel and purchased power contracts. This
may reduce future costs in what the Company expects will be a more competitive
environment.
The Company continues to be the sole provider in its certificated service
territories, however, the Company will continue to closely monitor the changes,
both locally and nationally, to prepare for competition.
SPR's investment in the transmission pipeline business will continue to
provide competitive alternatives and greater reliability to new and expanding
markets along its routes in Northern California and Nevada. It also provides
competitive alternatives for delivery of natural gas used as fuel for the
Company's power generation.
Like most other companies in the world, SPPC is facing the Year 2000
problems. The Company plans to have its problem resolved by December 31, 1998.
For information regarding regulatory changes affecting the Company, see
Rate Proceedings, Item 7, Nevada Matters, California Matters, FERC Matters and
-------------- ------------------- ------------
Note 2 of the Company's consolidated financial statements.
MERGER TERMINATION
------------------
In June 1994, the Company, SPR, and The Washington Water Power Company
(WWP) entered into a Merger Agreement which provided for the merger of the
parties into an entity named Resources West Energy Corporation. (That name was
later changed to Altus Corporation). Under the terms of the Merger Agreement,
if the merger was not consummated on or before June 27, 1996, either party, by
providing written notice to the other, could terminate the Merger Agreement
provided that party was not then in breach of any obligation
11
<PAGE>
under the Agreement which caused or resulted in the failure of the Merger
Agreement to be consummated by that date.
On June 28, 1996, WWP provided written notice to the Company and SPR that
it was terminating the Merger Agreement. Since that time, petitions to withdraw
merger applications have been filed by one or more parties in all jurisdictions
having approval jurisdiction over the merger.
As a result of the termination of the merger, the Company plans to continue
to operate as a separate utility and as a wholly-owned subsidiary of Sierra
Pacific Resources.
As a result of the termination of the merger certain filings were made in
various regulatory jurisdictions. See Note 2 of the Company's consolidated
financial statements.
ELECTRIC BUSINESS
-----------------
BUSINESS AND COMPETITIVE ENVIRONMENT
- ------------------------------------
The Company's electric business contributed $507 million (81.8%) of 1996
operating revenues. Typically the electric business peaks both in summer and
winter. The system has an annual load factor of approximately 75%, 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 (snow-making,
lifts, etc.). Summer peak loads result from air-conditioning, cooling equipment
and irrigation pumping. The Company's peak load increased an average of four
percent annually over the past five years, reaching 1,225 megawatts (MW) on July
22, 1996. The Company's electric MWH sales have increased an average of four
percent annually over the past five years.
A significant part of the growth in the Company's electric sales has
resulted from growth in the gold mining and gaming industries in northern
Nevada. Adverse developments with respect to either industry, or the loss of
large individual customers, through closure or use of competing providers, could
have a negative impact on the Company's electric sales.
The Company's electric customers by class contributed the following
percentages toward 1996 megawatt-hour sales:
<TABLE>
<CAPTION>
MWH SALES
----------
<S> <C>
Residential 25.4%
Commercial and Industrial:
Mining 24.5%
All Other 38.5%
Wholesale 10.0%
Miscellaneous 1.6%
-----
Total 100.0%
=====
</TABLE>
12
<PAGE>
Nevada leads the nation in gold production. The majority of Nevada gold
mines are located within the Company's service area. Nevada gold production for
1996 is estimated at about 7 million ounces, representing about 67% of U.S. and
9% of the world's production, respectively. The Nevada Bureau of Mines and
Geology at the University of Nevada, Reno, has estimated that current Nevada
gold reserves are sufficient to sustain substantial levels of production for 20
to 30 years, assuming stable prices.
During the last quarter of 1996, world gold prices fell from about $385 per
ounce to approximately $360 per ounce at year-end. Production costs vary widely
at Nevada mines. Mining industry reports indicate a high percentage of Nevada
gold is produced at a production cost of less than $300 per ounce, with larger
mines producing within the range of $175 to $210 per ounce. Should gold prices
remain in the mid $300 per ounce range or fall further, reductions in new
capital spending and exploration could occur.
The Company has negotiated and signed six long-term power sales contracts
with major mining customers. Five have been reviewed and approved by the Nevada
Commission with one additional contract pending approval as part of an overall
Commission review of a new rate tariff designed for major customers above 3 MW.
The Company is currently in negotiations and pursuing a total of four additional
contracts. These mining contracts represent over 250 megawatts of present and
future mining load, or approximately $86 million in annual revenue. They are
based upon customers attaining minimum annual demand and load factors, and
require minimum annual bills. Termination charge provisions include recovery of
all costs for customer-specific facilities and, for the first five years under
the contract, recovery of two years of minimum bills. The loss of any one of
these contracts would not have a material adverse effect on the Company.
The resorts and recreation group is comprised of hotels, casinos, and ski
resorts. The resorts and recreation market segment comprises 10.7 percent of
total electric system sales. Several of these large customers have finished or
are in the finishing stages of major expansions in 1996.
Over the past five years, MWH sales to wholesale customers have increased
at a compounded rate of 19%. During 1996, firm and non-firm sales to wholesale
customers comprised about 8% of total energy sales. The wholesale market is
very competitive and sales into this market are typically made at very low
margins.
<TABLE>
<CAPTION>
Percent
(MWH) of Total
-------- --------
<S> <C> <C>
Firm Sales 333,201 50.0%
Non-firm Sales 228,416 34.3%
Firm Off-System Sales 88,649 13.3%
Non-firm Off-System Sales 16,325 2.4%
------- -----
Total 666,591 100.0%
======= =====
</TABLE>
While the wholesale sales in 1996 represented 10% of sales they represent
only 4% of electric revenues. Recent changes in federal regulations covering
the rules under which transmission systems are 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.
------------
13
<PAGE>
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 California and Nevada.
The Company continues to prepare for a more competitive environment and has
actively participated in regulatory reform deliberations in Nevada and
California, and in federal proceedings. See Item 7, Nevada Matters, California
-------------- ----------
Matters, and FERC Matters.
- ------- ------------
Electric Integrated Resource Planning
- -------------------------------------
The Company is required by Nevada Law to conduct an integrated, least-cost
planning process for evaluating and acquiring its future electric system
resources. The Nevada Commission pre-approves the Company's electric resource
additions, which minimizes the chances of the Commission disallowing future
capacity projects or long-term purchase power contracts. See Rate Proceedings.
----------------
MAJOR PROJECTS SUMMARY
- ----------------------
The following projects were approved in previous resource plans. See Rate
----
Proceedings.
- -----------
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 will be fully capable of operating 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 facilities to
partially cool and clean the syngas produced by the gasifier. The current
rating is 106 megawatts in the winter and 89 megawatts in the summer. The DOE
is providing funding for approximately 50% of the construction cost and half of
the operating and fuel expenses for the first 42 months of operation. The DOE
has committed $168 million of funding for Pinon. Estimated construction start-
up and commissioning costs for Pinon, including the DOE's portion are
approximately $272.4 million, which includes permitting, taxes, start-up
commissioning, operator training and AFUDC. Expected DOE funding for
construction is $125.6 million. The Company and Foster Wheeler USA Corp., the
architect, engineer and construction manager on the project are currently
investigating the reasons for, exact nature and extent of, and responsibility
for cost increases on the entire Pinon project. The Company's cost per kilowatt
of capacity net of DOE construction and prior to the sale of the gasifier is
$1,390 based on the peak winter rating and $1,640 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. Engineering,
14
<PAGE>
procurement and construction activities are under way, with the gas and steam
portion (combined cycle) satisfactorily completed and placed in service December
1, 1996. The balance of the plant will be in service by mid-1997.
Pinon Pine Co. and Pinon Pine Investment Co., subsidiaries of the Company,
own 25% and 75%, respectively, of a 38% interest in The LLC with a subsidiary of
General Electric Capital Corporation (GECC) holding a 62% interest. The LLC was
formed to take advantage of federal income tax credits associated with the
alternative fuel (syngas) produced by the coal gasifier and available under
Section 29 of the Internal Revenue Code.
The Company is under contract to build and operate the gasifier portion of
the facility for Pinon Pine Co., LLC. The Company has also agreed to purchase
from The LLC the syngas produced in the gasifier for use in the Company-owned
power island. These contracts are contingent upon the gasifier meeting the
necessary requirements to be eligible for the (S) 29 credits. The contracts
also contain performance warranties which require the Company to make specified
payments to, or to purchase the gasifier from, the LLC under certain conditions.
See Note 5 of the Company's consolidated financial statements.
Alturas Intertie
- ----------------
The planned 345 KV line will originate at the Bonneville Power
Administration transmission line west of the northeastern California town of
Alturas. It will extend south 165 miles to an existing Company substation in
Reno. In January 1996, the California Commission certified the final
Environmental Impact Report/Statement (EIR/S) prepared for the project and
granted the Company a Certificate of Public Convenience and Necessity which
recognizes the need for and benefit of the project. To date, the Company has
spent $68.6 million on the project.
In February 1996, the lead federal agency, the Bureau of Land Management
(BLM) issued a positive Record of Decision for the project approving the
issuance of a right-of-way grant for approximately 70 miles of BLM land and
confirming that the EIR/S for the project meets the requirements of the National
Environmental Protection Act. Final Records of Decision have not yet been heard
by the Modoc National Forest or the Humboldt-Toiyabe National Forest. The
Company is continuing to work with the Modoc National Forest in California to
resolve outstanding environmental issues under their jurisdiction.
The Company and the Humboldt-Toiyabe National Forest (HTNF) were unable to
reach agreement with respect to the route for the line on HTNF lands.
Additionally, the Truckee Meadows Regional Planning Commission, citing land use
conflicts, failed to find the project in conformance with the regional plan.
To address these issues the Company has modified the southern portion of
the line in Washoe County and withdrawn its application with the HTNF. This
partial reroute has increased project costs by $15 million to approximately $135
million including AFUDC. This additional cost includes right-of-way ($3.5
million), transmission facilities ($3.5 million), additional environmental
matters ($3.0 million) and AFUDC ($5.0 million).
15
<PAGE>
The Company is working to conclude the permitting process and begin
construction in late summer 1997, assuming all required permits are obtained.
When operational, the project is expected to provide greater system reliability
and an additional route to bring in hydro-electricity from the Pacific
Northwest. If the Company is unable to meet the expected load forecast as a
result of the absence, or extended delay in completion of the intertie an
alternative would be the construction of generation within our control area.
FACILITIES AND OPERATIONS
- -------------------------
Total System
- ------------
As of December 31, 1996 the Company's electric transmission facilities
consisted of approximately 3,800 overhead pole line miles and 80 substations.
Its distribution facilities consisted of approximately 9,200 overhead pole line
miles, 4,300 underground cable miles and 176 substations.
The Company continues to maintain a wide variety of resources in its
generation system. During 1996 the Company generated 55% of its total electric
energy requirements in its own plants, purchasing the remaining 45% as shown
below:
<TABLE>
<CAPTION>
Percent
Megawatt-Hours of Total
-------------- --------
<S> <C> <C>
Company Generation
- ------------------
Gas/Oil 2,899,100 34.2
Coal 1,714,697 20.2
Hydro 54,801 0.6
--------- -----
Total Generated 4,668,598 55.0
--------- -----
Purchased Power
- ---------------
Long-Term Firm:
Utility Purchases 1,820,790 21.5
Non-Utility Purchases:
Geothermal 766,831 9.0
Other 134,309 1.6
Spot Market 1,090,909 12.9
--------- -----
Total Purchased 3,812,839 45.0
--------- -----
Total 8,481,437 100.0
========= =====
</TABLE>
Despite an increase in natural gas prices during 1996 over the lower
1995 level, generation from the Company's gas/oil-fired units made up the
largest percentage of total output at 34.2%.
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 1996 system peak, the Company had
purchased firm capacity under long-term contracts with other utilities and
qualifying facilities (QFs) equal to 23.5% of total system peak hour capacity.
In 1996, most of the Company's non-utility generation came from QFs, except for
20,252 megawatt hours, which came from two small power producers. The
percentage of spot market energy purchases (12.9%) was somewhat lower than the
16
<PAGE>
previous year but still well above pre-1995 levels. Wet weather conditions in
the Pacific Northwest created an abundance of low-cost energy during much of
1996, of which the Company took advantage whenever possible.
Load and Resources Forecast
- ---------------------------
The Company's total system capability and peak loads for 1996, and as
estimated for summer peak demand through 2001 (assuming no curtailment of supply
or load and normal weather conditions) are indicated below.
<TABLE>
<CAPTION>
Capacity at
1996 Peak Forecasted Summer MW
----------------- -----------------------------------------
MW % 1997 1998 1999 2000 2001
----------- --- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
Company Generation:
Existing 964 68% 1,053 1,053 1,053 1,053 1,053
----- --- ----- ----- ----- ----- -----
Purchases:
Long/Short-Term Firm(1)(2) 262 19% 295 294 292 285 285
Interruptible Customers 5 1% 5 5 5 5 5
Non-Utility Generators 74 5% 74 74 74 74 74
----- --- ----- ----- ----- ----- -----
Subtotal 341 25% 374 373 371 364 364
----- --- ----- ----- ----- ----- -----
Additional Required 104 7% 40 93 122 165 215
----- --- ----- ----- ----- ----- -----
Total System Capacity 1,409 100% 1,467 1,519 1,546 1,582 1,632
===== === ===== ===== ===== ===== =====
Net System Peak (3) 1,225 87% 1,280 1,330 1,352 1,385 1,433
Planning Reserve 184 13% 187 189 194 197 199
----- --- ----- ----- ----- ----- -----
Total 1,409 100% 1,467 1,519 1,546 1,582 1,632
===== === ===== ===== ===== ===== =====
Growth over
previous year 4.1% 3.5% 1.8% 2.3% 3.2%
===== ===== ===== ===== =====
</TABLE>
(1) Value net of losses.
(2) There are currently no contracts for short-term firm purchases. Values shown
represent potential purchases within existing transmission system limits.
(3) The system peak shown for 1996 is the actual system peak of 1,225 MW, which
occurred on July 22, 1996.
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 184 megawatts in 1996,
which the Company expects will increase to 197 megawatts by 2001. To
accommodate the system requirement during the 1997-2001 time period, it will be
necessary to secure additional capacity beginning in 1997. The Nevada
Commission, through the electric resource planning process, approved the Pinon
Pine Power Project, which will provide 89 megawatts beginning in 1997. The
"Additional Required" will be met by short-term purchases through 1998. The
17
<PAGE>
least-cost option for needs beginning in 1999 will be evaluated in the Company's
next Resource Plan filing due in 1998.
For information concerning the financing of the constructed generation
included in the preceding table, refer to the Construction Program section and
--------------------
the Management's Discussion and Analysis - Construction Expenditures and
Financing.
Generation
- ----------
The Company's total generating capability for the upcoming 1997 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 2 265 1981 and 1985
Tracy Steam/Gas, Resid. Oil 3 244 1963, 1965, 1974
Pinon Combined Cycle/Coal, Gas 1 89 1996 - 1997
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,
Propane, Hydro 35 91 1899 - 1970
-----
1,053
=====
</TABLE>
(CT) Combustion Turbine
(GT) Gas Turbine
The Company owns 100 percent of all of its electric generation plants with
the exception of Valmy. The Company 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 table above includes the generation capacity of the 100% SPPC-owned power
island portion of the Pinon Pine Power Project. The gasifier portion of Pinon
is owned by the Pinon Pine Co., LLC (The LLC). Pinon Pine Corp. and Pinon Pine
Investment Co., subsidiaries of the Company, own 25% and 75% of a 38% interest
in The LLC with General Electric Capital Corporation (GECC) owning the remaining
62%.
Four of the Company's hydro generation units are located on the Truckee
River, which runs approximately 110 miles from Lake Tahoe, through Reno/Sparks,
to Pyramid Lake. The Company also leases two units from the Truckee-Carson
Irrigation District under a 30-year operating lease which expires in 1998. The
units are in the Lahontan Reservoir area, 70 miles southeast of Reno. See
Leaseholds.
- ----------
Purchased Power
- ---------------
The Company continues to manage a diverse portfolio of contracted and spot
market supplies, as well as its own generation, in order to keep the Company's
net average system costs as low as possible. With the wet weather conditions
and mild temperatures prevailing in the Pacific Northwest over much
18
<PAGE>
of 1996, the Company was also able to purchase surplus economy energy at very
low costs.
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 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 spot market energy, both hydro and thermal-produced,
by the hour, based upon economics and system import limits. During drought
years, when less spot market hydro energy is available, the Company resorts to
energy produced by more expensive fossil fuels. For example, during the early
1990s drought conditions increased regional demand in the Pacific Northwest
which coupled with load growth restricted the availability of the region's hydro
energy resources. In recent years, however, very wet weather conditions in the
Pacific Northwest allowed the Company to purchase large amounts of surplus
economy energy at prices which had not been experienced since 1986. Of
continuing concern to any purchaser of hydro-generated energy are proposals by
regulators, in the interest of saving the salmon, recommending closure of some
hydro operations on the Snake and Columbia rivers. The amounts 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 secondary sales also will be 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 them has not been a problem for the Company in the past,
and is not expected to be a problem in the future.
<TABLE>
<CAPTION>
Minimum
Contract Operation Termination Capacity
Contract Party Capacity Date Date %
- -------------- -------- --------- ----------- --------
<S> <C> <C> <C> <C>
Idaho Power 75 MW Nov 1989 May 1999 50%
Idaho Power (for Elko) 15 MW Mar 1994 May 2000 40%
Tri-State 25 MW June 1991 Feb 2007 50%
PacifiCorp 75 MW June 1989 Feb 2009 70%
PacifiCorp/Utah Power (1) 75 MW May 1991 Apr 2021 78%
</TABLE>
(1) THE COMPANY HAS THE RIGHT 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, 1996, the Company had a total of 105
19
<PAGE>
megawatts of maximum contractual firm capacity under 15 contracts with QFs. The
Company also had contracts with four projects at fluctuating short-term avoided
cost rates. All contracts currently delivering power to the Company at long-
term rates have been approved by either the Nevada Commission or the California
Commission, and have QF status. These long-term QF contracts terminate under
their own provisions between 2006 and 2039.
The actual QF output of 74 megawatts during the summer 1996 peak was less
than the firm contracted amount of 105 megawatts. The table on page 17 reflects
actual performance during the 1996 summer peak period. Any capacity shortfall
created by under-performance was included in the Company's 1995 Resource Plan.
Energy purchased by the Company from QFs constituted 9% of the net system
requirements during 1996. These contracts continue to provide useful diversity
for the Company in meeting its load peak. All the QFs from which the Company
makes firm purchases are either geothermal (86%), hydroelectric or biomass.
Some QF contracts have been priced higher than alternative utility energy
suppliers in the past. The changing nature of some QF contracts has resulted in
lower prices to the Company. The long-term contract with California Energy
Company for the Desert Peak geothermal plant terminated in January 1996. A new
agreement with significantly lower pricing is now in place for future purchases
from that plant. Another long-term contract with Far West reverted to the lower
short-term avoided cost rates starting in December 1996.
The Company has been making spot market purchases at a reduced cost. The
Company has some control over dispatch in its newer purchased power contracts
with QFs. In addition, contract expiration dates are staggered to meet changes
in demand.
The Company's electric resource planning process has evaluated purchased
power as a supply-side alternative and prices have been competitive with
alternatives.
Transmission
- ------------
In planning its transmission capacity, the Company considers its generation
and purchased power needs, as well as the opportunity for providing retail and
wholesale wheeling 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 some 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
Pacificorp's Utah division. A 345 KV transmission line connects 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 interconnecting 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
20
<PAGE>
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.
21
<PAGE>
The Company's transmission intertie system provides access to
competitively-priced energy supplies. The existing system has played a major
role in helping stabilize the Company's energy costs by allowing surplus energy
purchases throughout the year, but especially during the spring snow melt in the
Pacific Northeast.
The Company also relies on transmission capacity to address system
emergencies, (such as the loss of generating units), reducing the need for
additional reserve generating capacity. The Company provides up to 148 MW of
transmission service under long-term firm contracts.
The Company is currently developing the Alturas Intertie to provide the
means of serving existing native load and new customers, and to significantly
increase the Company's access to lower cost resources. Assuming all required
permits can be obtained, the anticipated in-service date of this intertie is the
summer of 1998. The projected in-service date is dependent on the outcome of
outstanding regulatory approvals yet to be acquired. See Alturas Intertie.
The Company has agreements with Pacificorp's Utah division and Idaho Power
which allow for up to 50 megawatts of the energy purchased by the Company from
PacifiCorp to be transmitted through the Idaho Power system. The Company also
has an interconnection agreement with PG&E that requires PG&E to maintain a firm
transmission rating of 108 megawatts, provided the Company pays the Company for
any necessary system upgrades. The interconnection's major purpose is to
provide an alternative transmission path in the event of an emergency on the
Company's system. The Nevada Commission, in a previous electric resource plan
opinion and order, approved the payment for upgrades into the late 1990's.
These upgrades are considered regulatory assets and are amortized over lives
similar to Company-owned facilities. At December 31, 1996 these regulatory
assets amounted to $5 million. See Note 1 of the Company's consolidated
financial statements.
22
<PAGE>
Fuel Availability
- -----------------
The Company's 1996 fuel requirements for electric generation were provided
by natural gas (61%), coal (37%), and oil (2%). During 1996 natural gas
remained the economic generation fuel 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 1992-1996 were as follows:
<TABLE>
<CAPTION>
Cost per MMBtu
-------------------------------------
<S> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992
----- ----- ----- ----- -----
Gas $2.10 $1.65 $2.19 $2.19 $1.70
Coal 1.88 2.19 2.07 2.05 2.08
Oil 3.48 3.80 3.37 3.54 3.36
</TABLE>
Since commencing 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 been generally more expensive.
However, the Company has operated its gas/oil-fired units at increased levels
since 1989 due to the competitive pricing of natural gas during this time
period.
The Company's contract with Black Butte Coal Company (Black Butte), for
coal shipments from the Black Butte Mine in Wyoming to Valmy, is in effect until
June 30, 2007 or until all commitments required by the contract are delivered
and/or canceled. Given the current rate of consumption, the Company anticipates
meeting the minimum commitment required by the contract several years prior to
its 2007 termination date. At that time the Company will evaluate market
conditions and put in place lower cost strategies. This may include purchases
on the spot market.
The Company, in concert with the other owner of Valmy, Idaho Power, is
actively exploring and implementing options to more rapidly amortize the Black
Butte contract prior to its June 30, 2007 final expiration date. In late June
1996, the Company and Idaho Power spent $5 million to cancel all Black Butte
contractual requirements for the 1996-97 contract year. This cancellation had
three main benefits:
1. To give the Company and Idaho Power the opportunity and flexibility to
purchase coal on the lower cost spot market, reducing the overall fuel
cost to the Valmy station and increasing the plant's operations;
2. To reduce the coal inventory at the Valmy station; and
3. To save the differential rail transportation costs between coals
originating in Wyoming compared to replacement coals originating in
Utah.
In the fall of 1996 the Company agreed with Idaho Power to further reduce
the Black Butte balancing account through additional actions. Idaho Power
agreed to take delivery of quantities of Black Butte coal at the Jim Bridger
Power Station (which is located directly across Interstate 80 from the mine)
during the months of July, August and September. In return, the Company agreed
23
<PAGE>
to buy out an amount of Black Butte coal rather than coal from the Bridger mine.
The Company will pay this additional $1.5 million prior to the end of the 1996-
97 contract year on June 30, 1997.
The Company's coal contract with Canyon Coal Company (Canyon) which
provides coal from Canyon's Utah operations extends until the year 2003. The
original contract was with Coastal States Coal Company which was sold to Canyon
Fuel Company, LLC during 1996. The contract also contains volume commitments
which the Company expects to meet.
The total amount of coal burned at the Valmy Power Plant during 1996 was
1.1 million tons. As of December 31, 1996, the coal inventory balance was
307,017 tons, or roughly 54 days of consumption at 100% capacity. The Company
targets an average annual coal stock-pile sufficient to provide 30 days supply
at full load.
The Company has increasing gas demands and a need for firm capacity,
primarily for electric generation, but also for load growth in its LDC.
In 1995 Tuscarora Gas Transmission Company, jointly owned by subsidiaries
of SPR and TransCanada Pipelines, USA Limited (TransCanada), completed
construction and began service through its new interstate natural gas pipeline,
to the Tracy Power Plant. The 229-mile, 20-inch pipeline provides the Company
with 95,000 decatherms per day of firm transportation service and direct access
to the gas reserves of the Western Canadian Sedimentary Basin, one of the
largest known reserves of natural gas in North America. The Tuscarora capacity,
matched with upstream capacity on interconnecting pipelines, will substantially
reduce the historical gas curtailments experienced by the electric division and
provide a competitive alternative for fuel supply.
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 50,000-75,000 barrels at each of
its Tracy and Fort Churchill facilities. The actual residual oil inventory
level at these two sites was 144,882 barrels as of December 31, 1996 which is
equal to six days supply at 100% load factor operation. Total residual oil
consumption in 1996 was 147,395 barrels.
24
<PAGE>
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 $67.4 million in 1996 operating revenues
(11% of total company operating revenues). The LDC has experienced rapid
customer growth over the past 10 years as a result of population increases in
the Company's service territory, active recruitment of businesses into northern
Nevada, and special programs promoting the conversion from other energy sources
to natural gas. The Company's 1996 peak day send-out for its local distribution
system was 84,204 decatherms, occurring on January 22, 1996. A new record peak
day sendout of 114,375 decatherms occurred on January 13, 1997.
Natural gas offers economic and environmental advantages over other energy
sources for space heating, water heating and other uses in residential,
commercial and industrial markets. Growth in the residential and small
commercial sectors is expected to continue with a renewed emphasis on the
development of those areas where gas service is not yet available. Continued
successful economic development activity in 1996 should add additional
industrial gas sales in 1997.
The Company is responsible for securing its own gas supply. The Company
has personnel and resources in place to deal with the complexities and
opportunities presented by the current gas markets and regulatory environment.
The Company has purchased spot market and firm gas supplies to meet electric
generation fuel requirements since November 1988, and firm gas supplies to meet
its LDC requirements since June 1991.
The Company is an active participant in ongoing workshop discussions
examining issues relating to gas utility regulation in an increasingly
competitive environment. The participants of the workshop, sponsored by the
Nevada Commission, represent various customer and utility interests in the
State. The issue of further unbundling of natural gas services at the retail
level is particularly relevant to the Company's efforts to provide customers
choice in their purchases of energy and energy services.
A new firm transportation service was developed by the Company and approved
by the Nevada Commission during 1996. The new service provides eligible large
commercial and industrial customers with the option of higher priority firm
transportation service in addition to the already available interruptible
transportation service. The variable rate structure of the transportation
service tariffs allows the Company to compete with customer bypass initiatives
and alternative energy options. Currently two customers secure their own gas
supplies with the Company providing transportation service on its distribution
system.
The Company's natural gas LDC business is also subject to competition from
other forms of energy available to utility customers. Large customers with fuel
switching capabilities compare natural gas prices to alternative energy source
prices. To remain competitive, the Company offers an incentive natural gas
sales rate (INGR) to these customers.
25
<PAGE>
The Value Based Service Tariff (VBST) was developed in 1995 to compete with
the natural gas transportation options available to the Company's largest
customers. Currently, nine customers are taking service under VBST Service
Agreements. In addition to VBST and the transportation services available to
eligible large customers, the Company offers bundled firm sales services for all
customers.
With the construction of the Tuscarora Pipeline in 1995, the ability of
large customers to obtain firm transportation rights into northern Nevada
increases the choices available to natural gas customers in the area. Tuscarora
presents opportunities for business growth through expanded services in a
regional natural gas market.
NATURAL GAS INTEGRATED RESOURCE PLANNING
- ----------------------------------------
The Company prepares an integrated natural gas resource plan which is
required to be filed with the Nevada Commission every three years and covers a
year planning period. See Rate Proceedings.
----------------
FACILITIES AND OPERATIONS
- -------------------------
Natural gas purchased for the Company's retail gas customers and for use in
its electric generating plants is transported on several FERC regulated
pipelines.
Northwest Pipeline Corporation (Northwest), in conjunction with Paiute
Pipeline Company (Paiute), provides the Company access to natural gas supplies
in British Columbia, the Rocky Mountain region, and the San Juan basin.
Northwest is a major interstate pipeline stretching from the Canadian border at
Sumas, Washington, to the northwestern corner of New Mexico. Paiute
interconnects with Northwest at the Idaho/Nevada border and runs southwest to
the Reno/Lake Tahoe area of Nevada and California.
With completion of the Tuscarora Pipeline in 1995, SPR has a financial
interest in natural gas transmission facilities serving the northern Nevada
market. TGTC, a partnership between a subsidiary of SPR and a subsidiary of
TransCanada, began service in 1995. Tuscarora interconnects with Pacific Gas
Transmission (PGT) near Malin, Oregon and terminates at the Tracy Power Plant
east of Reno/Sparks. In addition to providing natural gas service to the
Company's Tracy Power Plant and distribution customers in the area, Tuscarora
Pipeline also provides service to the Company's main distribution system serving
the Company's retail gas customers in Reno/Sparks and the Truckee Meadows.
Tuscarora Pipeline also provides service to the community of Malin, Oregon and
the Sierra Army Depot near Herlong, California.
PGT is a major interstate pipeline stretching from the Canadian border at
Eastport, Idaho to the California/Oregon border near Malin, Oregon. NOVA and
Alberta Natural Gas (ANG) pipelines are upstream of PGT in the British Columbia
and Alberta provinces of Canada. Firm transportation service on Tuscarora and
upstream pipelines improves the reliability of the Company's gas supplies and
provides additional access to abundant and competitively priced supplies in
Alberta, Canada.
26
<PAGE>
The Company has contracted for firm winter-only and annual gas supplies
with 10 Canadian and domestic suppliers to meet the firm requirements of its LDC
and electric operations. The contracts total 120,000 decatherms per day through
March 1997; 40,000 decatherms per day for April through October 1997; and 50,000
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 facility located at Jackson
Prairie in southern Washington and LNG storage from a facility located in
Lovelock, Nevada. The LNG facility is operated by Paiute and is used for
meeting peak demand. The Jackson Prairie and LNG facilities can contribute a
total of approximately 45,000 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 PGT.
Starting November 1, 1996, the Company entered an agreement to sell winter
seasonal peaking 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 additional gas supplies
being delivered on Tuscarora Pipeline and because of the ability of its power
plants to utilize a variety of fuels.
27
<PAGE>
Following is a summary of the transportation and approximate storage
capacity of the Company's current gas supply system. 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.
<TABLE>
<CAPTION>
Transportation Capacity
- -----------------------
<S> <C> <C>
Northwest - 70,696 decatherms per day firm
90,000 decatherms per day interruptible
Paiute - 105,774 decatherms per day firm from November
through March
63,044 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
30,000 decatherms per day firm (winter only)
90,000 decatherms per day interruptible
Tuscarora - 95,000 decatherms per day firm
Storage Capacity
- ----------------
Northwest - 277,997 decatherms from Jackson Prairie
12,733 decatherms per day from Jackson Prairie
Paiute - 463,034 decatherms from Lovelock LNG
35,078 decatherms per day from Lovelock LNG
facility
</TABLE>
The Company's LDC natural gas requirements have averaged between 10 and 12
million decatherms annually over the past few years. Total LDC therm supply
requirements in 1996 and 1995 were 11.8 million decatherms and 10.8 million
decatherms, respectively. Electric generating fuel requirements for 1996 and
1995 were 31 million decatherms and 25 million decatherms, respectively.
As of December 31, 1996 the Company owned and operated 1,219 miles of
three-inch equivalent natural gas distribution lines.
28
<PAGE>
WATER BUSINESS
--------------
Business and Competitive Environment
- ------------------------------------
The local water distribution business contributed $45.3 million (7.3%) to
the Company's 1996 operating revenues.
The Company's water business is seasonal to the extent that nearly 70
percent of consumption occurs from May through September as a result of
residential and commercial irrigation needs. Permanent conservation measures
have resulted in a reduction of usage in drought and non-drought years.
The Company continues to pursue the Negotiated Settlement which has been in
the works for several years. The Company is currently operating under a
Preliminary Settlement Agreement (PSA) and Interim Storage Contract until the
final document is completed. The PSA is a complex set of agreements on Truckee
River issues involving the U.S., California, and Nevada governments and the
Pyramid Lake Paiute Tribe. Pursuant to the PSA, the Company and the other
parties are currently negotiating an operating agreement for the Truckee River
and reservoirs on the river, including Lake Tahoe and Boca Reservoirs for
drought storage for the Company. The Company will gain use of federal
reservoirs for drought reserves in exchange for providing excess non-drought
year water for fishery purposes.
The Negotiated Settlement, which is expected to be completed in 1997, will
resolve much outstanding litigation on the river. For the operating agreement
and PSA to become effective there must be a final resolution of outstanding
litigation involving the Company and the parties. Prior to completion, the
settlement must satisfy the National Environmental Protection Act (NEPA) through
an environmental impact study on the operating plan for the settlement
implementation which is expected to be filed in mid-1997. Related agreements
and water accounting systems are in development and expected to be finalized by
mid-1997. The water conservation and water quality agreements were completed in
1996.
Water obtained from the Truckee River and its tributaries is processed
through two major treatment facilities and combined with water pumped from 24
supply wells to serve the needs of the Company's water customers. The Company's
upstream reservoirs have a capacity of approximately 7.2 billion gallons of
untreated water storage. Additional storage of up to 4.6 billion gallons has
been secured in federal reservoirs under a 25-year contract signed in May 1994
or until the Negotiated Settlement goes into effect. This contract will be
replaced by a larger storage agreement once the Negotiated Settlement is in
place.
As a condition of the Negotiated Settlement, the Company's 45,000 unmetered
residential water customers must have meters installed. This retrofit program
began in 1995 and was approved by the Nevada Commission in early 1996.
Installation funding is provided by new business development. In the early
years of the 10 to 12 year program, our meters will be installed only for
customers who volunteer for the program. Once 90% of the meters have been
installed, the program may become mandatory. Through year-end 1996,
29
<PAGE>
meters have been installed in the homes of 6% of the previously unmetered
customers.
After the conversion of both the Hunter Creek and Highland Treatment
Facilities to treated water storage facilities, the Company will have water
storage capacity of approximately 106 million gallons in its treatment plant
reservoirs and distribution storage tanks. Due to this conversion, to treated
water storage from open storage, Highland will lose approximately 30 million
gallons of its capacity, which accounts for the reduction from 1995 to 1996.
Refer to Water Treatment Facilities.
As of December 31, 1996 the Company owned and operated 1,399 miles of six-
inch equivalent transmission and distribution mains. The total volume of water
distributed during 1996 and 1995 was approximately 22 and 20 billion gallons,
respectively. The Company's peak day send-out of water during 1996 was 117
million gallons, which was an increase from the 1995 peak of 111 million
gallons.
During 1995 comprehensive legislation was adopted by the Nevada Legislature
which provides for regional planning and cooperative management of all aspects
of water in the region and the ability of the County to create a remediation
district. The Regional Water Planning Commission was created to develop an
integrated water plan. The water plan was developed throughout 1996, and has
received all necessary approvals from local government entities. By April 1997
the plan will be submitted to the Nevada Legislature for its approval. The
Company and Washoe County have negotiated an agreement which provides
methodology to determine retail service area boundaries and establishes the
Company as the wholesale purveyor for the region. The parties are currently
waiting for approval of the agreement from the Nevada Commission. These
cooperative efforts between the Company and local agencies will help ensure
regional planning and integrated water service.
Supply and Integrated Resource Planning
- ---------------------------------------
The Company's water supplies are based on surface water and groundwater
sources, with the addition of drought storage and refill provisions sufficient
to withstand a repeat of the recent eight-year drought. The Company's water
supply during normal years consists of approximately 80 percent from the Truckee
River and 20% from local wells. During drought years, approximately 75% of
supply comes from the Truckee River and 25% from wells.
The river originates in Lake Tahoe and flows north and east through Reno
and Sparks to Pyramid Lake, northeast of Reno. During the drought, little water
flowed out of Lake Tahoe for four years, so other system tributaries and
reservoirs made up the stream flow. Normal flows and storage levels recovered
during 1995 and 1996. The 1997 winter season produced sufficient snowfall,
which, combined with the water storage remaining from 1996, should provide ample
water supplies through 2000.
The Company plans for future water supplies through the use of an
integrated analysis of demand projections, drought reserves and facility
capacity. The resulting water resource plan is submitted periodically to the
Nevada Commission for review and approval. The most recent Integrated Water
Resource Plan (1995 - 2015) was approved in 1994. Although there is no
30
<PAGE>
statutory requirement to file future integrated Water Resource Plans, the Nevada
Commission ordered that an update to the current plan be filed in 1998.
As part of the Water Resource Plan, the Company gained approval for three
additional sources of supply and upstream drought storage, increasing the
approved limit of the Company's water commitments from 82,000 acre feet annually
to 97,400 acre feet annually. This allows substantial margin for growth and
still have the Company capable of withstanding continued drought. An interim
storage contract was reached among the Company, the United States, the Pyramid
Lake Paiute Indian Tribe and Washoe County Water Conservation District. It
allows the Company to store up to 14,000 acre feet of water for drought use in
two federal reservoirs. The Negotiated Settlement discussed above provides the
greatest opportunity for drought storage beyond the Resource Plan time frame,
with sufficient drought storage to support annual customer demands of up to
119,000 acre feet annually.
Water Treatment Facilities
- --------------------------
The Safe Drinking Water Act (SDWA) amendments passed by Congress in 1986
significantly impacted the cost of the Company's treatment plant facilities. The
Company was officially notified in 1991 by the Nevada State Health Division
that, under the requirements of the Surface Water Treatment Rule (SWTR) of the
SDWA, filtration of water at its non-filtered plants would be required. The
Company submitted and received approval of a filtration compliance plan with the
Nevada State Health Division. The plan provided for a three-year extension of
the original deadline to June 1996.
In order to comply with SWTR filtration requirements and meet projected
capacity demands, the Company has completed the construction of a second phase
of the Chalk Bluff treatment plant. The first phase, completed in spring 1994,
provided a capacity of 27 million gallons per day (MGD) using high- rate
filtration approved by the State Health Department. The second phase of the
facility, with a capacity of 42 MGD, was completed in April 1996. The Company's
Glendale treatment plant also underwent enhancements to its treatment processes
which were completed in June 1996. Completion of these projects results in full
compliance with the SWTR requirements.
The Company's Idlewild chemical-process treatment plant was removed from
operation in 1994 and now serves as a transfer pumping station. Of the two
remaining chemical-process plants, Hunter Creek was removed from operation as a
treatment facility in October 1995 and was converted to a covered storage
facility in May 1996. Highland was removed from operation as a treatment
facility in June 1996, and is being converted to a 20 MGD storage facility to be
completed by May 1997. Combined, Hunter Creek and Highland will provide 50
million gallons of treated water storage for fire protection, operating storage
and emergency requirements.
The Company uses groundwater from 24 supply wells. Manmade contaminants
from local business operations, in levels exceeding drinking water standards,
have been found in five of these wells. Treatment equipment costing $2.2
million has been installed on two of the wells and the wells have been returned
to operations. The three other wells have been removed from operation. The
Company has entered into a bilateral compliance agreement with
31
<PAGE>
the Nevada State Health Division which requires these three wells to be in
compliance by October 1998. The Company continues its involvement in a
cooperative remediation effort with public officials to determine the source and
extent of the contaminant and to develop a plan to abate the contamination on an
area-wide basis. Washoe County has the ability to create a special remediation
district to help cover the cost of this effort. The County Commission passed a
resolution initiating proceedings to create the remediation district, and will
be proposing legislative amendments to facilitate the establishment of the
district. The remediation plan is expected to be developed by June 1998.
As of December 31, 1996, the Company has spent approximately $114 million
on water treatment improvements and treated water storage facilities. These
investments include Chalk Bluff, Glendale, well treatment, and the Highland and
Hunter Creek Reservoirs. An estimated $15 million will be spent in 1997-2001
for additional treatment improvements.
32
<PAGE>
CONSTRUCTION PROGRAM
--------------------
Construction expenditures, including allowance for funds used during
construction (AFUDC), for 1996 were $180 million and for the period 1991 through
1996 were $811.4 million. Estimated construction expenditures for 1997 and the
period 1998-2001 are as follows (dollars in thousands):
<TABLE>
<CAPTION>
Total
1997 1998-2001 5-Year
--------- ----------- ---------
<S> <C> <C> <C>
Electric Facilities $111,091 $ 398,631 $509,722
Water Facilities 21,240 45,202 66,442
Gas Facilities 9,565 35,051 44,616
Common Plant 4,579 11,516 16,095
-------- ---------- --------
Total Construction Expenditures 146,475 490,400 636,875
AFUDC (8,456) (9,651) (18,107)
Net Salvage, including cost of removal 1,089 3,648 4,737
Net Customer Advances and
Contributions in Aid of
Construction (3,634) (14,491) (18,125)
-------- ---------- --------
Total Cash Requirements $135,474 $ 469,906 $605,380
======== ========== ========
</TABLE>
Total construction expenditures estimated for 1997-2001, for each
segment of the Company's business, consist of the following (dollars in
thousands):
<TABLE>
<CAPTION>
Total
1997 1998-2001 5-Year
-------- ---------- ---------
Electric Facilities:
<S> <C> <C> <C>
System Improvements $ 35,697 $ 219,843 $255,540
New Business Extensions 31,468 130,647 162,115
New Transmission 28,517 37,560 66,077
New Generation 14,284 - 14,284
Other 1,125 10,581 11,706
-------- ---------- --------
$111,091 $ 398,631 $509,722
======== ========== ========
Water Facilities:
Treatment Plant Improvements 11,860 3,149 15,009
Distribution Improvements 7,487 27,684 35,171
New Business Extensions 1,305 5,770 7,075
Other 588 8,599 9,187
-------- ---------- --------
$ 21,240 $ 45,202 $ 66,442
======== ========== ========
Gas Facilities:
New Business Extensions $ 6,922 $ 27,428 $ 34,350
Other 2,643 7,623 10,266
-------- ---------- --------
$ 9,565 $ 35,051 $ 44,616
======== ========== ========
</TABLE>
The numbers in the preceding table represent currently planned
construction expenditures of the Company. There are a number of items discussed
in the foregoing business sections that are not included in the table, such as:
---
(1) additional investment which may be required to serve the total electric load
forecasted for the 1997-2001 time period (see the table on page 17. Refer to
Item 7 Management's Discussion and Analysis.
The Company anticipates no significant expenditures for compliance
with the Clean Air Act amendments of 1990. Refer to Environment.
-----------
33
<PAGE>
The Company's estimated construction program is prepared annually
within guidelines imposed by changing economic, regulatory and environmental
conditions which may alter the nature and estimated cost of the program.
Included in the category of Electric Facilities, System Improvements, is $4.9
million for damage replacements due to the flood of 1997. In the category of
Water Facilities Treatment Plant Improvement, is $1.6 million primarily for
flood damage to the Glendale Water Treatment Facility.
GENERAL REGULATION
------------------
The Company is subject to the jurisdiction of the Nevada and
California Commissions 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 Nevada Commission 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 Nevada Commission for
approval.
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 that the Company utilizes.
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 the authorities referred
to under the Environment.
-----------
34
<PAGE>
RATE PROCEEDINGS
----------------
During 1996, 90.6% the Company's revenues were from retail sales of
electricity, natural gas and water in Nevada; 6.8% from retail sales of
electricity in California and 2.6% from sales of electricity for resale in
Nevada and California.
NEVADA MATTERS
- --------------
In December 1994, the Nevada Commission approved the Company's request to
combine its 1995 Electric and Natural Gas Integrated Resource Plan in a single
filing. In September 1995 the Nevada Commission approved this Resource Plan in
its entirety. Among many components of the plan, are these three-year Action
Items:
1. Approval of a natural gas purchasing strategy;
2. Approval to permit the Fort Churchill site to accommodate two 90
megawatt combustion turbines; and
3. Approval to develop a new generation site.
On November 7, 1996, the Company received an operating permit from the
Nevada Division of Environmental Protection for two 83 MW combustion turbines
for the Fort Churchill site. In 1996, the Company selected an
architectural/engineering consultant to perform a generation siting study
anticipated to be completed in April 1997. At that time a new site will be
selected.
In the 1995 resource plan, the Company prepared a strategy for Demand Side
Management that responds to the pressure of growing competition and the price of
its basic product. The Company continues to design and pursue cost effective
demand side management through the Custom Energy Solutions Program and the
Interruptible Program where it continues to make economic sense for its
customers. The next electric resource plan is due to be filed mid-1998.
The 1995-2014 Electric and Gas Integrated Resource Plan contains forecasts
of future natural gas demand and the Company's plans to meet those requirements
economically while maintaining service reliability and flexibility. Also
included in the plan are distribution facility additions including the Company's
LDC interconnection with the Tuscarora Pipeline. The resource plan identifies
the criteria used in evaluating gas supply contracts, the proposed mix of firm
and interruptible natural gas supplies, and the supply sources required to meet
peak day demands over the planning period. The next gas resource plan is due mid
1997.
The Company intends to file a water rate case in 1997 to recover cost
increases related to investments in water plant to comply with the Safe Drinking
Water Act.
See Item 7, Nevada Matters, California Matters, and FERC Matters and Note 2
-------------- ------------------ ------------
of the Company's consolidated financial statements.
35
<PAGE>
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.
The Nevada Utility Environmental Protection Act requires Nevada Commission
approval prior to the construction of major utility generation and transmission
facilities. The Nevada Division of Environmental Protection and the Federal
Environmental Protection Agency administer regulations involving air quality,
water pollution, solid, hazardous and toxic waste.
The Company's Board of Directors has a comprehensive environmental policy
and separate board committee on environmental compliance which oversees
corporate performance and achievements related to the environment. Through its
employees, the Company's business activities are guided by the corporate
environmental policy, which places environmental considerations at the forefront
of the decision-making process.
1996 ACTIVITIES
- ---------------
Start-up of the combined cycle power island of the Pinon Pine Power Project
in December 1996 was a significant event. A DOE Clean Coal Technology Project,
Pinon will be capable of burning natural gas or gas synthesized from coal.
Besides providing the flexibility to burn the most economic fuel available,
pollutant and greenhouse gas emission rates are significantly lower than those
from conventional or scrubbed coal generation units. As an added benefit, water
use per unit of electricity produced is much lower than for other similar power
plants.
The Company conducted compliance audits on 59 sites, including eight
vendor sites. During 1996, remediation was performed on eight sites at a cost
of more than $320,000. In addition, 28 spills were successfully remediated. In
1995 the Company identified one site that was formerly used for manufacturing
gas from oil. Currently, the Company has negotiated a sale of this parcel. The
Company's total liability for this site is estimated to be $500,000, of which
approximately $250,000 has been spent through December 31, 1996. The remaining
balance has been accrued as a liability on the December 31, 1996 consolidated
balance sheets.
In 1996, 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
cost of compliance with environmental regulations.
Once again the Company was awarded bonus sulfur dioxide emission allowances
by the US Environmental Protection Agency (EPA) for use of
36
<PAGE>
geothermal energy, a renewable resource. Sierra received 666 bonus allowances in
1996. Under the Acid Rain Rule of the Clean Air Act, bonus emission allowances
are granted to utilities that have avoided sulfur dioxide emissions by using
renewable energy to generate electricity or by reducing electricity demand with
energy conservation and efficiency measures. Only four US utilities have been
awarded more bonus allowances than the Company.
As a voluntary Climate Challenge participant, the Company filed with the
DOE its second annual report on greenhouse gas emissions and actions taken to
reduce them. Carbon dioxide, the principal greenhouse gas, is produced when oil,
natural gas or coal is combusted. Some scientists are concerned that rising
levels of carbon dioxide and other greenhouse gases may lead to rapid changes in
climate conditions, potentially resulting in serious economic and environmental
impacts. About 3.7 million tons of carbon dioxide were produced from the
Company's generating units; however, emissions could have been about 665,000
tons more if certain actions had not been taken, representing a 15% reduction.
Use of renewable resources (geothermal and hydroelectric energy), energy
conservation and efficiency measures, generating unit efficiency improvements,
increased use of natural gas over oil (a benefit of the Tuscarora Pipeline
Project completed in 1995), reuse of coal fly ash in cement production, and
natural gas use in fleet vehicles contributed to offset carbon dioxide
emissions.
Stewardship of Nevada's water and wildlife resources is being demonstrated
at the Fort Churchill and Tracy power plants. At Fort Churchill the Company
expanded its 1995 wetland restoration efforts with a joint effort at the
wetlands on the Mason Valley Wildlife Refuge. The Refuge, adjacent to the
Walker River, is administered by the Nevada Department of Wildlife (NDOW). This
cost and resource-sharing partnership between the Company, NDOW, and Ducks
Unlimited involves use of cooling water from the Company's facilities. Water
will be piped to wetland ponds on the Refuge, expanding open water recreation
opportunities and wildlife habitat by about 500 acres. Besides enhancing water
resources in the region, this project is an inexpensive way to improve cooling
systems at the generating units.
Implementation of a riparian habitat improvement project and planning for
an 80 acre wetland restoration project at Tracy Power Plant occurred in 1996.
The riparian project consists of removing an invasive weed along the Truckee
River and planting willows and cottonwood trees. Besides providing bank
stability along the cooling pond levee, habitat for birds and mammals will be
enhanced and river water quality conditions improved. The 80 acre wetland
restoration project will have similar environmental benefits, in addition to
reducing the potential for flood damage in the vicinity of the power plant.
While the Company has been involved with waste minimization projects for
years, during 1996 a formal pollution prevention program was initiated. The
Company's Pollution Prevention Program will increase awareness of wasteful
practices and products, and introduce decision-making tools and processes which
have been shown to prevent, reduce, reuse, or recycle hazardous, solid and
liquid waste streams.
In September 1994, the United States Environmental Protection Agency Region
VII (EPA) notified the Company that it was being named as a potentially
37
<PAGE>
responsible party (PRP) regarding the past improper handling of PCBs by PCB
Treatment, Inc. located in Kansas City, Kansas and Kansas City, Missouri (the
Sites). 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 PRP's have 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. EPA has 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 both a removal site evaluation
to determine the nature and extent of the contamination at the sites and an
engineering evaluation/cost analysis to determine and evaluate alternatives for
removal action to prevent, mitigate, or otherwise respond to or remedy the
release or threatened potential subsequent release of hazardous substances. The
consultant will also perform a streamlined risk assessment that includes
contaminant identification, exposure assessment, toxicology assessment and human
health and environmental risk characterization. The Company has recorded a
preliminary liability for this site of $500,000 of which approximately $26,000
has been spent through December 31, 1996. The remaining balance is shown as a
liability on the December 31, 1996 consolidated balance sheets. Once the
removal site evaluation and the engineering evaluation/cost analysis are
completed, the Company will be in a better position to estimate and record the
ultimate liabilities for this site.
38
<PAGE>
GENERAL
-------
FACILITIES
- ----------
The Company's general office building is located at 6100 Neil Road, Reno,
Nevada. The facility is leased by the Company for an initial term of 25 years,
which will end on June 30, 2010. The lease includes six renewal options for
five years each and two renewal options for 10 years each. See Note 14 of the
Company's consolidated financial statements.
Other major facilities include the operations center, transportation
building and warehouse located at Ohm Place in Reno and 13 business
offices/service centers located throughout the Company's service territory.
LEASEHOLDS
- ----------
The Company operates portions of its electric system as lessee under lease
agreements with Truckee-Carson Irrigation District (TCID) and Mineral County
Power System.
Under terms of the TCID lease, the Company is obligated to pay an annual
lease payment of $108,000 plus 2% of gross revenues derived from operations
within the leasehold area, which covers portions of Washoe (excluding
Reno/Sparks), Lyon, Storey and Churchill counties. In 1996, the Company paid
approximately $351,000 as 2% of gross revenues. The lease expires in July 1998,
at which time TCID is obligated to purchase any Company capital improvements
unless the lease is renewed. To date, capital improvements, net of
depreciation, total $21.3 million.
Under terms of the Mineral County Power System 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 1996 the Company paid $145,000 on
gross revenues of $6.2 million. The lease expires in 2000. As with TCID,
Mineral County Power System is obligated to purchase any Company capital
improvements unless the lease is renewed. To date, capital improvements, net of
depreciation, total $7.2 million.
39
<PAGE>
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 acquies
cence, 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
varying payments based either on gross revenues, in which case the Company
collects the fees directly through customer billings and remits to grantors of
the franchise, or net profits from operations, which the Company records as
expense. Franchise payments expense aggregated $1.0 million during 1996.
Following are the Company's major franchises.
<TABLE>
<CAPTION>
Franchise Type of Service Expiration Date
- --------- ----------------------- -----------------
<S> <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 Lake
Tahoe 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.
40
<PAGE>
RESEARCH, DEVELOPMENT AND DEMONSTRATION
- ---------------------------------------
The Research, Development and Demonstration (RD&D) mission is to establish,
encourage and execute RD&D related activities in pursuit of corporate
excellence. In particular, the focus is on the activities to improve customer
competitiveness and satisfaction, while strengthening the Company's corporate
financial position.
The RD&D program includes elements managed and executed locally, those in
participation with other utilities through the Electric Power Research Institute
(EPRI), the Gas Research Institute, the American Gas Association, the American
Waterworks Association, and other utility groups. These activities focus on
performance improvements of existing utility facilities, effective resource
utilization, efficiency improvements for customers' equipment, technologies, and
generation technology for alternative energy resources.
The Company donated its electric vehicle to the University of Nevada, Reno
for development of a special metropolitan area transportation project utilizing
the electric vehicle as a pilot instant rent-a-car.
The Company's strategy includes effective use of technology to improve its
business processes, existing and future. The key to this strategy is timely
implementation of proven technologies, such as those resulting from its
collaborative research and testing efforts with EPRI. The Company also supports
future technology applications with investments in energy-related technology.
For example, through SPR's partnership investments in Nth Power Fund, an R&D
Venture Capital Fund, the Company has the opportunity to adopt and profit from
new energy-related technologies.
41
<PAGE>
ITEM 2. PROPERTIES
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.
See Item 1 - Business.
ITEM 3. LEGAL PROCEEDINGS
The Company, 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.
42
<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>
1996
-----------------
<S> <C>
First Quarter $16,000
Second Quarter 16,000
Third Quarter 16,000
Fourth Quarter 16,000
-------
Total 1996 $64,000
=======
1995
-----------------
First Quarter $ -
Second Quarter 27,000
Third Quarter 14,000
Fourth Quarter 15,000
-------
Total 1995 $56,000
=======
</TABLE>
Note: The dividends scheduled above represent payments from the Company to
its parent, SPR. Dividends declared by SPR on its publicly traded stock totaled
$36.1 million during 1996.
Future dividends are subject to factors that ordinarily affect dividend
policy, such as future earnings and the financial condition of the Company.
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, 1996 approximately $72.5 million of retained
earnings was available for the payment of dividends on common stock under the
most restrictive of these limitations.
43
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended December 31,
(dollars in thousands)
-------------------------------------------
1996 1995 1994 1993 1992
------------ ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Operating Revenues $ 619,724 $ 597,784 $ 603,193 $ 521,568 $ 476,769
========== ========== ========== ========== ==========
Operating Income $ 107,008 $ 101,811 $ 95,983 $ 90,562 $ 84,823
========== ========== ========== ========== ==========
Income Before Preferred
Dividends $ 75,400 $ 65,983 $ 60,863 $ 57,457 $ 49,843
========== ========== ========== ========== ==========
Income Applicable
to Common Stock $ 67,351 $ 58,609 $ 52,929 $ 49,196 $ 44,203
========== ========== ========== ========== ==========
Total Assets $1,842,628 $1,729,818 $1,605,710 $1,554,896 $1,392,490
========== ========== ========== ========== ==========
Long-Term Debt and
Redeemable Preferred
Stock $ 655,787 $ 547,124 $ 531,233 $ 526,177 $ 536,654
========== ========== ========== ========== ==========
Cash Dividends Paid
on Common Stock $ 63,000 $ 54,000 $ 51,000 $ 48,000 $ 44,200
========== ========== ========== ========== ==========
</TABLE>
44
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
---------------------
Net income before preferred dividends in 1996 was $73.7 million, an
increase of $7.7 million compared to 1995. The Company's most recent three-year
average return on year-end common equity was 10.5%. For 1996 the Company was
authorized to earn a return on equity of 12% in its Nevada electric department,
and 11.5% and 11.75%, respectively, in its Nevada gas and water departments. In
November 1995, the California Commission changed the electric authorized return
on common equity from 11.3% to 11.6%, effective January 1, 1996.
On February 6, 1997, the Nevada Commission approved a new rate plan. As
part of the new rate plan the Company will refund $13 million to electric
customers. The Company recorded this refund in 1996 as a reduction in revenues.
See Note 2 of the Company's consolidated financial statements.
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 (i.e., consumption by customer class) can result in increases or decreases
in revenues, regardless of changes in total consumption.
The components of revenue margin are set forth below (dollars in
thousands):
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
Operating Revenues:
<S> <C> <C> <C>
Electric $507,004 $491,419 $498,680
Gas 67,376 62,572 65,174
Water 45,344 43,793 39,339
-------- -------- --------
Total Revenues 619,724 597,784 603,193
-------- -------- --------
Energy Costs:
Electric 223,177 212,473 244,404
Gas 32,479 37,330 41,296
-------- -------- --------
Total Energy Costs 255,656 249,803 285,700
-------- -------- --------
Revenue Margin $364,068 $347,981 $317,493
======== ======== ========
Revenue Margin by Division:
Electric $283,827 $278,946 $254,276
Gas 34,897 25,242 23,878
Water 45,344 43,793 39,339
-------- -------- --------
Total $364,068 $347,981 $317,493
======== ======== ========
</TABLE>
45
<PAGE>
Energy costs are comprised of purchased power, fuel for power generation,
gas purchased for resale and deferred energy. Average energy costs are set
forth below:
<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Average cost per KWH
of purchased power 3.15cents 3.35cents 3.64cents
Average cost per KWH
of generated power 2.20cents 2.02cents 2.31cents
Average cost per therm of
gas purchased for resale 27.48cents 32.74cents 29.12cents
</TABLE>
The $15.6 million, 3.2%, increase in electric operating revenues during
1996 generally followed the regional increase in customers. The $7.3 million,
1.5%, decrease in 1995 electric operating revenues, compared to 1994, was due
primarily to the $18.8 million fuel rate decrease granted by the Nevada
Commission on May 1, 1995. This decrease was offset by a simultaneous $6.5
million general base rate increase and continued customer and MWH sales growth.
Gas operating revenues for 1996 increased $4.8 million, 7.7%, over 1995,
due to increased sales and continued customer growth. 1995 gas operating
revenues were down $2.6 million, 4.2%, compared to 1994, primarily due to warmer
weather in the fourth quarter of 1995. This decrease was partially offset by
continued customer and gas sales growth throughout the year.
Water department revenues increased $1.6 million, 3.5%, during 1996,
primarily as a result of customer growth. Water revenues increased $4.5
million, 11.3%, during 1995 over 1994, reflecting a full year of a $6 million
rate increase and customer growth.
During 1996, the Company increased both its levels of electric generation
and power purchases in order to keep pace with the increasing demand for
electricity. Kilowatt hours generated in 1996 increased 11.3% from 1995 levels,
and kilowatt hours purchased increased 8.7% during the same period. The total
cost of electric generation per kilowatt hour increased 8.9% from 1995 to 1996,
driven by a 20.9% increase in the cost of fuel between years. This increase in
fuel costs is due primarily to an increase in the cost of natural gas over the
lower levels of 1995. Despite this increase, natural gas remained the fuel of
choice for 1996, rather than oil or coal. The total cost of purchased power
increased only $2.8 million, 2.1%, from 1995 to 1996. The increase in volume of
power purchases and the reduced cost per KWH are due to increased availability
of inexpensive hydro-electric power from the Northwest, as a result of wet
winter weather in that region. For 1995 purchased power and fuel costs for
power generation decreased by $6.7 million, 5.3%, and $5.1 million, 5.6%,
respectively, from 1994. During the same period, the Company increased
generation by 7.7% and purchased power 1.3%, however, the combined cost of both
declined from 1994 due to lower unit costs of purchased power and natural gas.
For 1996, while the Company increased total therms of natural gas purchased
for resale by 8.0%, the total cost of acquiring those therms decreased by $3.3
million, 9.3%, due to a 16.1% decrease in per-therm cost,
46
<PAGE>
from 1995. Purchased gas in 1995 was up $2.1 million, 6.3%, from the prior year
due to a 12.4% increase in unit costs, and a 2.6% reduction in weather-related
sales.
Deferral of energy costs-net decreased following the suspension of deferred
energy accounting in the Company's California jurisdiction. The 1996 income
represents the write-off of the over-collected balance at the time of the
suspension. Deferral of energy costs-net decreased from 1994 to 1995, following
the Nevada Commission authorized change in deferred energy accounting. In March
1995, the remaining balances in the Company's (Nevada jurisdiction, only)
deferred energy receivables accounts were collected and the Company suspended
use of the deferred energy accounting methodology. Fluctuations in purchased
gas, fuel and purchased power expenses from the base fuel rates are now
reflected in earnings. Refer to Note 2 of the Company's consolidated financial
statements for discussion of deferred energy accounting.
Other operating expenses including labor, services and materials were up
$1.6 million, 1.3%, from 1995, excluding the cost of a coal contract buy-out.
Including the cost of the $4 million coal contract buy-out, these 1996 operating
expenses were up 4.7% over 1995. The 1995 expenses were $10.3 million, 9.6%,
higher than for 1994 due primarily to $11.6 million of merger expense. 1995 and
1996 increases in wages for bargaining unit employees, and additional water
treatment expenses were offset by staff reductions.
The Company's gas and water departments experienced negligible increases in
maintenance expense in 1996. Electric department maintenance expense was up
$1.8 million, 11.4%, in 1996, due primarily to maintenance on the Valmy power
plant boiler $506,145, transmission stations $625,841, and overhead lines
$333,591. Maintenance costs were up $2.2 million, 13.3%, in 1995 over 1994, due
primarily to the overhaul of two turbine generators at the Tracy plant and
maintenance of overhead distribution lines.
Continued additions to utility plant contributed to an increase in
depreciation expense of $3.1 million, 5.5%, over the prior year for both 1996
and 1995.
Operating income taxes declined $1.1 million, 3.0%, in 1996, due to the
deductibility of merger expenses following the termination of the merger.
Operating income taxes for 1995 increased by $8.3 million, 28.4%, over 1994 due
to increased pre-tax income and the tax impact of merger costs, a portion of
which were not expected to be deductible for tax purposes.
Increases in property, franchise, and other non-income taxes accounted for
the $1.1 million, 6.4%, increase in this category for both 1996 and 1995 over
the prior years. These increases are consistent with the increase in revenues
and utility plant.
Allowance for funds used during construction (AFUDC) is calculated using
rates commensurate with the cost of debt and equity financing. For 1996, the
AFUDC rate was higher than in 1995; and combined with higher construction-work-
in-progress (CWIP) balances for the Alturas Intertie project, the Chalk Bluff
water plant, and plant associated with the Pinon project throughout 1996, caused
a doubling in AFUDC. The increase in AFUDC from 1995 was due to higher CWIP
balances, especially in electric and water departments, offset slightly by lower
rates.
47
<PAGE>
For 1996, other income(expense)-net was significantly higher ($.9 million
income vs. $3.4 million expense) than in 1995. The 1995 data included among
other items: non-recurring expense adjustments for transition interest and
customer shared savings program; a change in tax regulations related to water
department trust fund interest in 1994; lower carrying charge income; and a
potential overcharge related to facilities. The 1995 amount was lower than in
1994 due to a reduction in carrying charge income, a reduction in income from
the variable rate note trust; and a reduction in non-operating income tax.
Other interest expense increased $2.8 million in 1996, due primarily to the
absence of 1995 reversal adjustments that reduced interest expense that year.
Other interest expense for 1995 was $4.1 million, 69.5%, lower than 1994 due
primarily to reversal of interest accruals related to IRS audit matters.
48
<PAGE>
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------------------
CONSTRUCTION EXPENDITURES AND FINANCING
- ---------------------------------------
The table below shows cash construction expenditures and net internally
generated cash for 1994 - 1996 (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994 Total
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Cash Construction Expenditures $179,101 $133,088 $108,822 $421,011
======== ======== ======== ========
Net Cash Flow from Operating
Activities $110,666 $153,935 $126,645 $391,246
Less: Cash Dividends Paid 69,559 61,420 58,981 189,960
-------- -------- -------- --------
Net Internally Generated
Cash $ 41,107 $ 92,515 $ 67,664 $201,286
======== ======== ======== ========
Net Internally Generated Cash
as a Percentage of Cash
Construction Expenditures 23% 70% 62% 48%
======== ======== ======== ========
</TABLE>
The Company's estimated construction expenditures for 1997-2001 are
detailed in the Construction Program section. The Company estimates that 37% of
its 1997 cash construction requirements will be provided by internally generated
funds; 63% will be provided by a variety of other sources including issuance of
long-term and short-term debt.
During 1997 the Company anticipates receiving $25 million of common equity
contributions from SPR. The 37% internal cash generation measure assumes that
100% of SPPC's net income is dividended to SPR. If actual SPR dividends were
used instead of the Company's dividend to SPR, the ratio would increase to 61%.
Estimated construction expenditures for 1997 and the period 1998-2001 are
as follows (dollars in thousands):
<TABLE>
<CAPTION>
Total
1997 1998-2001 5-Year
---------- ----------- ----------
<S> <C> <C> <C>
Electric Facilities $111,091 $398,631 $509,722
Water Facilities 21,240 45,202 66,442
Gas Facilities 9,565 35,051 44,616
Common Plant 4,579 11,516 16,095
-------- -------- --------
Total Construction
Expenditures 146,475 490,400 636,875
AFUDC (8,456) (9,651) (18,107)
Salvage, Net of Cost of
Removal 1,089 3,648 4,737
Net Customer Advances and
Contributions in Aid of
Construction (3,634) (14,491) (18,125)
-------- -------- --------
Total Cash Requirements $135,474 $469,906 $605,380
======== ======== ========
</TABLE>
49
<PAGE>
CAPITAL STRUCTURE
- -----------------
On January 3, 1995, the Company replaced its lines-of-credit arrangements
with an $80 million revolving credit facility, thus assuring itself a committed
facility to support its commercial paper borrowings. At December 31, 1996, the
Company had $38.0 million of short-term borrowings outstanding, all of which
were in commercial paper. The Company's commercial paper is rated P2, A2 and
D1- by Moody's, Standard & Poor's and Duff & Phelps, respectively.
The Company's actual capital structure at December 31, 1996, 1995 and 1994
was as follows (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
------------------ ------------------ -----------------
<S> <C> <C> <C>
Short-Term Debt (1) $ 53,434 (4%) $ 63,208 (5%) $ 58,683 (5%)
Long-Term Debt 607,287 (44%) 533,524 (43%) 510,833 (43%)
Preferred Stock 121,615 (9%) 86,715 (7%) 93,515 (8%)
Common Equity 606,896 (43%) 567,383 (45%) 531,277 (44%)
--------------- --------------- ---------------
$1,389,232 (100%) 1,250,830 (100%) 1,194,308 (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, 1996, these coverage provisions would allow for the
issuance of approximately $477 million in additional first mortgage bonds at an
assumed interest rate of 8%. The Company's long-term debt is rated A3, A- and
A- by Moody's, Standard & Poor's and Duff & Phelps, respectively. The Company's
pre-tax interest coverages for 1996, 1995, and 1994 were 3.50, 3.78, and 3.21,
respectively.
On November 13, 1996 SPR's Board of Directors declared a common dividend of
$16.0 million, that was paid February 1, 1997, and a preferred dividend of $1.4
million, that was paid on March 1, 1997. On February 18, 1997, the Company's
Board declared both common ($18.0 million) and preferred ($1.4 million)
dividends, payable May 1, and June 1, 1997, respectively.
50
<PAGE>
In December 1996, the Company registered $35 million of collateralized debt
securities. See Note 6 of the Company's consolidated financial statements.
On June 3, 1996, the Company redeemed the remaining 408,000 shares of Series
G, 8.24% Preferred Stock, at par value, for $20.4 million.
On July 29, 1996, Sierra Pacific Capital I, (the Trust), a wholly-owned
subsidiary of the Company, issued $48.5 million (1,940,000 shares) 8.60% Trust
Originated Preferred Securities (the Preferred Securities). See Note 7 of the
Company's consolidated financial statements.
NEVADA MATTERS
- --------------
Under Nevada law, general rate increases must be based upon 12 months
experienced (historic) costs. A 12-month historic test year may be updated an
additional 90 days for certified expenditures and revenues. The Nevada
Commission is obligated to issue its final decision within 180 days after the
filing.
As provided by statute, the Company is allowed to use deferred energy
accounting procedures in its retail electric and gas operations. The intent of
these procedures is to capture fluctuations in the cost of purchased gas, fuel
and power. Deferred energy accounting allows a utility to defer the difference
between actual monthly expense and the rates it is allowed to recover from its
customers. The procedures also allow for an annual updating of fuel and
purchased power costs and the amortization of deferred balances over a 12-
month period. An optional mid-year filing can occur if the increase or decrease
in total revenues exceeds 5%. The Company has suspended deferred energy
accounting in its Nevada and California jurisdictions. See Notes 1 and 2 of the
Company's consolidated financial statements.
As a result of the termination of the merger certain filings were made. See
Note 2 of the Company's consolidated financial statements.
Nevada has begun investigating various proposals which could result in a
restructuring of the electric industry and increase competition among power
providers. On June 28, 1996, the Nevada Commission issued an order in its
electric restructuring investigation which approved forwarding to a Legislative
Subcommittee a report entitled "The Structure of Nevada's Electric Industry:
Promoting the Public Interest". That report concluded that the Nevada
Commission should continue to acquire information relating to past costs,
uneconomic bypass, unbundling, and the potential for anticompetitive practices.
Workshops are continuing to be scheduled to investigate these and other issues
related to Nevada's electric industry. The Subcommittee issued a report to the
Legislature for consideration during the 1997 legislative session. The Company
cannot predict the outcome of these investigations or the effect that the
adoption of any such proposals would have on the Company or its future earnings.
51
<PAGE>
CALIFORNIA MATTERS
- ------------------
SPPC utilizes an Energy Cost Adjustment Clause (ECAC) which provides for
electric deferred energy accounting procedures similar to those described under
"Nevada Matters" above. In addition, the California Commission permits the use
of the following adjustment mechanisms: Attrition Rate Adjustment (ARA), a
procedure used to adjust rates between tri-annual general rate filings and
Electric Revenue Adjustment Mechanism (ERAM), a procedure used to adjust
revenues for fluctuations in sales from those levels adopted in a general rate
case decision.
During the merger time frame the Company reached agreements with the
California Commission concerning these mechanisms. As a result of the
termination of the merger certain filings were made. See Note 2 of the
Company's consolidated financial statements.
On September 24, 1996, the Governor of California signed into law a bill
restructuring California's electric services industry and reforming regulation.
That bill provided for the restructuring of the electric industry beginning
January 1, 1998. The law included creation of an Independent System Operator
(ISO) to efficiently operate the State's transmission system and ensure
comparable access for power suppliers. It will also create a Power Exchange
(PX) to function as a spot market for electricity, and over time, to provide
customers direct access to alternative suppliers. Utility provisions of
performance-based ratemaking will be applied to remaining monopoly distribution
services. Stranded costs will be recovered through a separate competitive
transition charge on customers' bills.
On March 4, 1997, the California Senate Committee on Energy, Utilities and
Communications met to discuss how provisions of the restructuring bill apply to
small and multi-jurisdictional utilities such as the Company. The committee
reviewed the relevant provisions of the legislation and clarified that utilities
have the option to request recovery of stranded costs. Utilities requesting
recovery of stranded costs are required to freeze rates at June 10, 1996 levels
and provide a 10% rate reduction for residential and small commercial customers.
The committee also clarified that if utilities do not request recovery of
stranded costs they are not required to participate in the ISO and PX. All
utilities, including the Company, are required to make direct customer access
available (based upon a yet unreleased California Commission phase-in plan)
beginning January 1, 1998, so long as transmission facilities linking the
utility to the ISO grid exist.
FERC MATTERS
- ------------
On April 24, 1996, the FERC issued its final rules concerning transmission
open access and stranded cost recovery. These were finalized in FERC Orders 888
and 889. The rules require that all public utilities that own and/or control
transmission facilities must file tariffs that allow third parties to utilize
the transmission facilities on a comparable basis to the use by the transmission
owners. The transmission provider must provide tariffs that allow third parties
to purchase point-to-point transmission service or service that has multiple
points of receipt and delivery, much the
52
<PAGE>
same as the provider, which is called network service. The orders also require
that the transmission provider "unbundle" the transmission rates into a
transmission-only rate plus ancillary services for generation and scheduling
activities performed by the provider. The purchase of the ancillary services by
the customer from the transmission provider is largely optional.
The Company filed its initial tariffs for open access transmission service
by July 9, 1996 as required by FERC Order 888 (the Order). Final acceptance and
approval of the filed rates are expected to occur over the following year, with
the resulting rates, terms and conditions determined by the FERC for each
utility. The impact of the new transmission rate and the provision of expanded
transmission service have not been fully determined at this time.
On July 12, 1996, the Company and six other northwest electric companies
signed a memorandum of understanding to study the feasibility of creating an
independent transmission grid operator (INDEGO) to insure non-discriminatory,
open access to electric transmission facilities in compliance with the FERC
rulings. Since that date, 12 other utilities have joined the group bringing the
current number of participants to 19. The group plans to file the INDEGO
proposal with FERC by the summer of 1997, and anticipates that limited operation
would commence in early 1999.
Another requirement of the Order is for utilities to establish an
electronic bulletin board (OASIS) to facilitate the purchase and sale of
transmission service. The Company has contracted with Salt River Project to
meet this requirement and is part of the Southwest OASIS (SWOASIS). The SWOASIS
became operational January 3, 1997 in accordance with FERC requirements, and can
be found on the internet (http://www.swoasis.com).
The Order also requires a distinct separation of personnel who act as
wholesale marketers and as transmission marketers. The Company accomplished
this requirement through restructuring into business units that separate these
functions under different officers. The wholesale marketers for the Company no
longer have exclusive access to information related to the transmission system.
The wholesale marketers are required to place service requests and purchases
based on information provided on the OASIS in the same manner as all other third
parties.
OTHER
- ------
Inflation affects the prices the Company and its subsidiaries must pay for
labor, materials, equipment and supplies used in operations, maintenance and
construction. Changes in fuel, purchased power and purchased gas costs, as a
result of inflation or otherwise, were recovered through balancing account
mechanisms, in years prior to 1995. Beginning in April 1995, changes in these
costs, like all other costs, are recovered through general rate requests.
Regulatory principles generally provide for recovery of the original cost of
plant investment. To the extent that the Company experiences regulatory lag,
the effects of inflation included therein are unrecovered.
53
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
Page
----
<S> <C>
FINANCIAL STATEMENTS:
REPORTS OF INDEPENDENT ACCOUNTANTS.............................. 55
Consolidated Balance Sheets
As of December 31, 1996 and 1995......................... 57
Consolidated Statements of Income
Years Ended December 31, 1996, 1995 and 1994............. 58
Consolidated Statements of Common Shareholder's Equity
Years Ended December 31, 1996, 1995 and 1994............. 59
Consolidated Statements of Capitalization
As of December 31, 1996 and 1995......................... 60
Consolidated Statements of Cash Flows
Years Ended December 31, 1996, 1995 and 1994............. 61
Notes to Consolidated Financial Statements.................. 62
</TABLE>
54
<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 sheet and consolidated
statement of capitalization of Sierra Pacific Power Company and subsidiaries as
of December 31, 1996, and the related consolidated statements of income, common
shareholder's equity, and cash flows for the year then ended. 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 audit. The consolidated financial statements for the years ended December
31, 1995 and 1994 were audited by other auditors whose report, dated February
16, 1996, expressed an unqualified opinion on those statements.
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 audit provides a reasonable basis for our opinion.
In our opinion, such 1996 consolidated financial statements present fairly, in
all material respects, the financial position of the Company as of December 31,
1996, and the results of its operations and its cash flows for the year then
ended in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Reno, Nevada
February 14, 1997
55
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of Sierra Pacific Power Company and subsidiaries as
of December 31, 1995, and the related consolidated statements of income, cash
flows, and shareholder's equity for the years ended December 31, 1995 and 1994.
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, the financial statements referred to above present fairly, in
all material respects, the financial position of Sierra Pacific Power Company
and subsidiaries at December 31, 1995, and the consolidated results of its
operations and its cash flows for each of the two years in the period ended
December 31, 1995 in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
San Francisco, California
February 16, 1996
56
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
December 31,
1996 1995
---------- ----------
<S> <C> <C>
ASSETS
------
Utility Plant, at Original Cost:
Plant in service $1,984,781 $1,816,444
Less accumulated provision for depreciation 606,406 556,710
---------- ----------
1,378,375 1,259,734
Construction work in progress 164,835 153,067
---------- ----------
1,543,210 1,412,801
---------- ----------
Non-utility Investments 22,394 22,519
---------- ----------
Current Assets:
Cash and cash equivalents 890 1,373
Accounts receivable less provision for
uncollectible accounts: 1996 - $2,196
1995 - $1,543 94,782 91,262
Materials, supplies and fuel, at average cost 27,586 30,455
Other 3,948 2,346
---------- ----------
127,206 125,436
---------- ----------
Deferred Charges:
Regulatory tax asset 67,667 69,610
Other regulatory assets 67,319 82,841
Other 14,832 16,611
---------- ----------
149,818 169,062
---------- ----------
$1,842,628 $1,729,818
========== ==========
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common shareholder's equity $ 606,896 $ 567,383
Preferred stock 73,115 73,115
Preferred stock subject to mandatory redemption - 13,600
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 -
Long-term debt 607,287 533,524
---------- ----------
1,335,798 1,187,622
---------- ----------
Current Liabilities:
Short-term borrowings 38,000 56,000
Current maturities of long-term debt
and redeemable preferred stock 15,434 7,208
Accounts payable 53,998 90,815
Accrued interest 6,178 5,300
Dividends declared 17,365 16,785
Accrued salaries and benefits 11,300 9,265
Other current liabilities 21,560 11,998
---------- ----------
163,835 197,371
---------- ----------
Deferred Credits:
Accumulated deferred federal income taxes 162,438 158,972
Accumulated deferred investment tax credits 41,835 43,797
Regulatory tax liability 42,870 45,084
Customer advances for construction 39,429 40,168
Other 56,423 56,804
---------- ----------
342,995 344,825
---------- ----------
Commitments and Contingencies (Note 14) $1,842,628 $1,729,818
========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
57
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
----------- --------- ---------
<S> <C> <C> <C>
Operating Revenues:
Electric $507,004 $491,419 $498,680
Gas 67,376 62,572 65,174
Water 45,344 43,793 39,339
-------- -------- --------
619,724 597,784 603,193
-------- -------- --------
Operating Expenses:
Operation:
Purchased power 122,272 119,464 126,190
Fuel for power generation 102,601 84,878 89,937
Gas purchased for resale 32,519 35,864 33,739
Deferral of energy costs-net (1,736) 9,597 35,834
Other 123,178 117,619 107,327
Maintenance 20,672 18,391 16,235
Depreciation and Amortization 58,118 55,065 52,176
Taxes:
Income taxes 36,241 37,370 29,113
Other than income 18,851 17,725 16,659
-------- -------- --------
512,716 495,973 507,210
-------- -------- --------
Operating Income 107,008 101,811 95,983
-------- -------- --------
Other Income:
Allowance for other funds used
during construction 5,231 1,245 2,042
Other income(expense)-net 867 (3,378) 2,363
-------- -------- --------
6,098 (2,133) 4,405
-------- -------- --------
Total Income Before Interest Charges 113,106 99,678 100,388
-------- -------- --------
Interest Charges:
Long-term debt 37,051 35,326 35,193
Other 4,579 1,781 5,834
Allowance for borrowed funds
used during construction and
capitalized interest (3,924) (3,412) (1,502)
-------- -------- --------
37,706 33,695 39,525
-------- -------- --------
Income Before Mandatorily
Redeemable Preferred Securities 75,400 65,983 60,863
Preferred Dividend Requirements of
Company-Obligated Mandatorily
Redeemable Preferred Securities (1,749) - -
-------- -------- --------
Income Before Preferred Dividends 73,651 65,983 60,863
Preferred Dividend Requirements (6,300) (7,374) (7,934)
-------- -------- --------
Income Applicable to Common Stock $ 67,351 $ 58,609 $ 52,929
======== ======== ========
</TABLE>
The accompanying notes are an integral part of the financial statements.
58
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
Common Stock
- ------------
Balance at Beginning of Year
and End of Year $ 4 $ 4 $ 4
-------- -------- --------
Other Paid-In Capital
- ---------------------
Balance at Beginning of Year 482,434 447,106 406,793
Additional investment
-------- -------- --------
by parent company 36,000 35,328 40,313
-------- -------- --------
Balance at End of Year 518,434 482,434 447,106
-------- -------- --------
Retained Earnings
- -----------------
Balance at Beginning of Year 84,945 84,167 95,422
Income before preferred dividends 73,651 65,983 60,863
Preferred stock dividends declared (5,879) (9,205) (7,981)
Common stock dividends declared (64,000) (56,000) (64,000)
Cost of issuing common stock
(reimbursement to parent company) (259) - (137)
-------- -------- --------
Balance at End of Year 88,458 84,945 84,167
-------- -------- --------
Total Common Shareholder's
Equity at End of Year $606,896 $567,383 $531,277
======== ======== ========
</TABLE>
The accompanying notes are an integral part of the financial statements.
59
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
December 31,
1996 1995
----------- -------------
<S> <C> <C>
Common Shareholder's Equity:
- ---------------------------
Common stock, $3.75 par value,
1,000 shares authorized, issued and outstanding $ 4 $ 4
Other paid-in capital 518,434 482,434
Retained earnings 88,458 84,945
---------- ----------
Total Common Shareholder's Equity 606,896 567,383
---------- ----------
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
---------- ----------
Subtotal 73,115 73,115
Subject to mandatory redemption:
$50 par value; Series G; $4.12 dividend - 13,600
---------- ----------
Total Preferred Stock 73,115 86,715
---------- ----------
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 -
---------- ----------
Long-Term Debt:
- --------------
First Mortgage Bonds:
6.50% Series K due 1997 - 15,000
Unamortized bond premium and discount, net (906) (947)
---------- ----------
Subtotal, excluding current portion (906) 14,053
---------- ----------
Debt Secured by First Mortgage Bonds:
2.00% Series Z due 2004 135 155
2.00% Series O due 2011 1,736 1,852
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 8.65% Series A MTN due 2022 115,000 115,000
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 -
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 3,335 3,395
6.70% Series II due 2032 21,200 21,200
---------- ----------
Subtotal, excluding current portion 527,456 447,652
---------- ----------
Variable Rate Note:
Water Facilities Note: maturing 2020 80,000 80,000
Total Funds Held in Trust - ( 9,175)
---------- ----------
Subtotal 80,000 70,825
---------- ----------
Other, excluding current portion 737 994
---------- ----------
Total Long-Term Debt 607,287 533,524
---------- ----------
TOTAL CAPITALIZATION $1,335,798 $1,187,622
========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
60
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
----------- ---------- ----------
Cash Flows From Operating Activities:
- ----------------------------------------
<S> <C> <C> <C>
Income before preferred dividends $ 73,651 $ 65,983 $ 60,863
Non-cash items included in income:
Depreciation and amortization 58,118 55,065 52,176
Deferred taxes and investment tax credits 1,233 (2,699) (9,376)
AFUDC and capitalized interest (9,155) (4,657) (3,544)
Deferred energy costs (1,736) 9,597 35,834
Deferred interest on variable rate debt (602) (708) (67)
Early retirement and severance amortization 7,877 2,127 1,488
Merger costs 1,909 11,612 -
Other non-cash 3,405 3,427 3,074
Changes in certain assets and liabilities:
Accounts receivable (3,520) (15,965) (18,356)
Materials, supplies and fuel 2,869 935 (236)
Other current assets (1,602) 820 85
Accounts payable (36,817) 41,260 389
Other current liabilities 12,475 (5,814) 11,190
Other - net 2,561 (7,048) (6,875)
--------- --------- ---------
Net Cash Flows From Operating Activities 110,666 153,935 126,645
--------- --------- ---------
Cash Flows Used in Investing Activities:
- ----------------------------------------
Additions to utility plant (203,109) (144,197) (125,478)
Non-cash charges to utility plant 9,475 5,059 3,980
Customer (refunds) advances for construction (739) (571) 1,070
Contributions in aid of construction 15,272 6,621 11,606
--------- --------- ---------
Net cash used for utility plant (179,101) (133,088) (108,822)
Disposal of (Investment in) subsidiaries and
other non-utility property-net 681 (16,950) (565)
--------- --------- ---------
Net Cash Used in Investing Activities (178,420) (150,038) (109,387)
--------- --------- ---------
Cash Flows From (Used in) Financing Activities:
- ----------------------------------------------
(Decrease) Increase in short-term borrowings (16,059) 12,635 (4,641)
Proceeds from issuance of long-term debt 80,041 - -
Retirement of long-term debt (427) (10,383) (7,364)
Decrease in funds held in trust 9,175 23,058 22,203
Retirement of preferred stock (20,400) (6,800) (6,800)
Proceeds from Company-obligated Mandatorily
Redeemable Preferred Securities 48,500 - -
Additional investment by parent company 36,000 35,329 40,313
Expenses of external financing - (59) (309)
Dividends paid (69,559) (61,420) (58,981)
--------- --------- ---------
Net Cash From (Used in) Financing Activities 67,271 (7,640) (15,579)
--------- --------- ---------
Net (Decrease) Increase in Cash and
Cash Equivalents (483) (3,743) 1,679
Beginning Balance in Cash and Cash Equivalents 1,373 5,116 3,437
--------- --------- ---------
Ending Balance in Cash and Cash Equivalents $ 890 $ 1,373 $ 5,116
========= ========= =========
Supplemental Disclosures of Cash Flow Information:
- -------------------------------------------------
Cash Paid During Year For:
Interest $ 41,256 $ 37,706 $ 36,617
Income taxes 39,993 40,177 36,232
</TABLE>
The accompanying notes are an integral part of the financial statements.
61
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
General
-------
Nature of Operations
- --------------------
The Company is a public utility primarily engaged in the generation,
purchase, transmission, distribution and sale of electric energy. It provides
electricity to approximately 278,000 customers in a total service area of
approximately 50,000 square miles, including western, central and northeastern
parts of Nevada, including the cities of Reno, Sparks, Carson City and Elko. The
Company also serves a portion of eastern California, including the Lake Tahoe
area.
The Company also provides natural gas to approximately 96,000 customers in
a total area of about 600 square miles in Reno/Sparks and surrounding area. It
supplies water service to about 63,000 customers in the Reno/Sparks metropolitan
area of about 160 square miles.
Subsidiaries
- ------------
In 1995 the Company formed two subsidiaries for the specific purpose of
investing in a Limited Liability Company with a subsidiary of General Electric
Capital Corporation (GECC) in the Pinon Pine gasifier facility. These
subsidiaries, Pinon Pine Corp. and Pinon Pine Investment Co. own 25% and 75%,
respectively, of a 38% interest in Pinon Pine Co., LLC. See Note 4 of the
Company's consolidated financial statements.
On July 29, 1996, the Company formed a wholly-owned subsidiary, Sierra
Pacific Power Capital I (Trust), for the purpose of completing a public offering
of trust originated preferred securities. See to Note 5 of the Company's
consolidated financial statements.
These subsidiaries are consolidated into the financial statements of the
Company, with all significant intercompany transactions eliminated.
Basis of Presentation
- ---------------------
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 and 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 those
estimates.
The Company maintains its accounts for electric and gas operations in
accordance with the uniform system of accounts prescribed by the FERC and for
water operations in accordance with the uniform system of accounts prescribed by
the National Association of Regulatory Utility Commissioners.
62
<PAGE>
Certain reclassifications have been made for comparative purposes but have
not affected previously reported income before preferred dividends or retained
earnings.
Utility Plant
-------------
In addition to direct labor and material costs, the Company also charges
the following costs to the construction of utility plant: 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, which is calculated monthly on the total funds
expended.
The original cost of plant retired or otherwise disposed of and the cost of
removal less salvage are 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
---------------------------------------------------------------------
The Company 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 a reasonable return on other funds used for construction
purposes in accordance with rules prescribed by the FERC and the Nevada
Commission. AFUDC is capitalized in the same manner as construction labor and
material costs, with an offsetting credit to "other income" for the portion
representing other 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 1996, 1995 and 1994 were 8.91%, 8.16% and
8.59%, respectively. As specified by the Nevada Commission, 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 method over the
estimated remaining service lives of the related properties. The provision, as
authorized by the Nevada Commission, for 1996, 1995 and 1994, stated as a
percentage of the original cost of depreciable property, was 3.18%, 3.16%, and
3.15%, respectively.
63
<PAGE>
Cash and Cash Equivalents
-------------------------
Cash is comprised of cash on hand and working funds. Cash equivalents
consist of high quality investments in commercial paper of other corporations
with original maturities of three months or less.
The Company engages in short-term investment activity whenever it is deemed
beneficial. As of December 31, 1996 and 1995, the Company had no commercial
paper investments (cash equivalents).
Other Regulatory Assets
-----------------------
Accounting for the utility business conforms with generally accepted
accounting principles as applied to regulated public utilities and as prescribed
by agencies and the commissions of the various locations in which the utility
businesses operate.
In accordance with these principles, certain costs that would otherwise be
charged to expense or capitalized as plant costs are deferred as regulatory
assets based on expected recovery from customers in future rates. Management's
expected recovery of deferred costs is based upon specific ratemaking decisions
or precedent for each item. The following other regulatory assets were included
in the consolidated balance sheets as of December 31 (dollars in thousands):
<TABLE>
<CAPTION>
DESCRIPTION 1996 1995 AMORTIZATION PERIODS
- ----------- -------- -------- --------------------
<S> <C> <C> <C>
Early Retirement and Severance Offers $29,195 $43,269 Various through 2005
Loss on Reacquired Debt 19,113 19,872 Various through 2023
Plant Assets 9,888 7,462 Various through 2031
Conservation and Demand Side Programs 6,805 9,069 Various through 2006
Other Costs 2,318 3,169 Various
------- -------
Total $67,319 $82,841
======= =======
</TABLE>
64
<PAGE>
Deferral of Energy Costs
------------------------
The Company has suspended deferred energy accounting in its Nevada and
California jurisdictions. Prior to May 1995 (Nevada) and June 1996
(California), the Company employed deferred energy accounting procedures in its
electric and natural 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 the Company to record
the difference between actual fuel expense and fuel revenues as deferred energy
costs. Refer to Note 2 of the consolidated financial statements.
Federal Income Taxes and Investment Tax Credits
-----------------------------------------------
For regulatory purposes, the Company 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, the Company began
providing for deferred taxes on the benefits of using the Accelerated Cost
Recovery System for all post-1980 property. In 1987 the TRA required the
Company to begin providing deferred taxes on the benefits derived from using the
Modified Accelerated Cost Recovery System.
Investment tax credits (ITC) are no longer available to the Company. The
deferred ITC balance is amortized over the estimated service lives of the
related properties.
The Company is part of an affiliated group that files consolidated tax
returns with its parent, SPR. The income tax provision of the group is
allocated to each of the subsidiaries as if each 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 sheets date.
Revenues
--------
The Company 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.
NOTE 2. REGULATORY ACTIONS
- ---------------------------
Nevada Proceedings
------------------
In September 1994, the Nevada Commission approved a stipulation to settle
the pending general rate case. The stipulation specified that the pre-1987
methodology be used to calculate fuel recoveries in deferred energy accounting.
The original transition balance that arose when the methodology was changed in
1987 was offset by this change. Interest of $4.8 million on the transition
balance was moved to a regulatory asset account. Amortization of this
regulatory asset was completed in December 1996. While the suspension of
deferred energy accounting continues, fluctuations in gas purchased for resale,
fuel and purchased power costs from the base fuel rates will flow through
earnings.
65
<PAGE>
The September 1994 stipulation also allowed for the deferred electric and
gas energy rates to remain intact until the full deferred energy balances were
recovered. In March 1995, the balances in SPPC's (Nevada jurisdiction) deferred
energy accounts were collected and SPPC suspended use of the deferred energy
accounting methodology, increased base rates by $6.5 million and decreased
deferred fuel rates by $18.8 million.
As a result of the termination of the merger, and as required by the
September 1994 stipulation, the Company filed with the Nevada Commission an
application to decrease deferred energy rates $8.2 million and increase
purchased gas rates $1.3 million effective January 1, 1997. The Company also
filed an application pursuant to the provisions of General Order 43 cost
recovery mechanism to decrease its general rates by $1.4 million plus
amortization of a balance of $3.6 million. The filings were accompanied by a
motion to adopt the rate plan previously approved by the Nevada Commission in
the proceeding related to the merger. Hearings concerning the motion were held,
and additional discussions were conducted which resulted in a stipulated rate
plan. The rate plan, approved by the Nevada Commission on February 6, 1997,
includes: a one-time refund of $13 million to Nevada electric customers, a
decrease of $7.1 million in electric rates, a rate freeze for electric and
natural gas rates through December 31, 1999, continued suspension of deferred
energy accounting. In addition, the deferred energy and purchased gas filings
were withdrawn and the General Order 43 cost recovery filing was resolved by an
additional $2.4 million decrease in electric rates.
The Nevada rate plan also provides for a 50/50 sharing between customers
and shareholders of electric and gas utility earnings in excess of a 12 percent
return on equity. SPPC has an opportunity, subject to certain conditions to
apply such excess to buying down or buying out of long-term fuel and purchased
power contracts currently in place. The $13 million refund is included in
current liabilities in the accompanying consolidated balance sheets.
California Proceedings
----------------------
As a result of the termination of the merger certain filings were made in
SPPC's California jurisdiction. In a previous decision, which conditionally
approved the merger, SPPC was required to file various rate applications for
test year 1997 in the event the merger was not consummated by March 31, 1996.
In a second decision, the California Commission extended this deadline and
suspended deferred energy accounting, which reduced SPPC's rates by $2.3 million
effective June 1, 1996. With termination of the merger, another decision was
issued which ordered a rate freeze through December 31, 2000 and continued the
suspension of deferred energy accounting.
66
<PAGE>
NOTE 3. UTILITY PLANT
- ----------------------
Utility plant in service consisted of (dollars in thousands):
<TABLE>
<CAPTION>
December 31,
------------
1996 1995
------------ ----------
<S> <C> <C>
Electric $1,545,045 $1,445,478
Water 300,431 241,015
Gas 139,305 129,951
---------- ----------
$1,984,781 $1,816,444
========== ==========
</TABLE>
NOTE 4. JOINTLY-OWNED FACILITIES
- ---------------------------------
VALMY
- -----
The Company 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. The Company is the operator of the
plant for both parties.
The Company's share of direct operation and maintenance expenses for Valmy
is included in the consolidated statements of income.
The following schedule reflects the Company's 50% ownership interest in
jointly-owned electric utility plant at December 31, 1996 (dollars in
thousands):
<TABLE>
<CAPTION>
Electric Accumulated Construction
MW Plant Provision For Work In
Plant Capacity In Service Depreciation Progress
- ----------- -------- ---------- ------------- ------------
<S> <C> <C> <C> <C>
Valmy #1 129 $127,252 $46,070 $385
Valmy #2 137 $153,580 $44,593 $284
</TABLE>
PINON PINE
- ----------
Pinon Pine Corp. and Pinon Pine Investment Co., subsidiaries of SPPC, own
25% and 75%, respectively of a 38% interest in Pinon Pine Co., LLC (The LLC),
with General Electric Capital Corporation (GECC) owning the remaining 62%. The
LLC was formed to take advantage of federal income tax credits available under
IRC (S)29 from the production and sale of an alternative fuel (syngas) produced
by the coal gasifier. 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 signed several contracts with The LLC. These contracts include a
fixed-price turn-key construction agreement, site and space leases, an operation
and maintenance agreement, a working capital loan agreement and a syngas
purchase agreement. In addition, SPPC has a funding arrangement with
67
<PAGE>
the 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 total DOE contribution is capped at $168 million, and through
December 31, 1996 the DOE has funded $115.6 million.
The fixed-price construction contract provides that The LLC will pay SPPC
$92.0 million for the gasifier. SPPC's obligations under the contract include
construction and start-up of the gasifier, and integration of the gasifier
facility into the operation of SPPC's post-gasification equipment and power
island. One-half of the $92.0 million cost will be funded by the DOE. The
remainder of the cost will be paid by The LLC. The LLC will fund this
construction commitment through a $20.4 million contribution of construction-
work-in-progress by SPPC at the time The LLC was created, and additional capital
contributions by GECC of $32.6 million. The LLC will not pay more than $46.0
million of the 92.0 million construction price.
Costs incurred above the 92.0 million contract price will be absorbed by
the Company and the DOE without reimbursement from The LLC. Foster Wheeler USA
Corp. the architect, engineer and construction manager on the project has
estimated that construction costs on the LLC-owned gasifier will overrun the
contract price by $2.7 to $3.3 million, after the DOE funding. The Company and
Foster Wheeler, USA Corp. are currently investigating the reasons for, exact
nature and extent of, and responsibility for cost increases on the entire Pinon
project. Total costs are now estimated to be $272.4 million.
The original in-service date was expected to be December 31, 1996 as
required to take advantage of the (S)29 credits. However, Congress extended the
deadline relative to the credits to June 30, 1998 and the gasifier is now
expected to be completed and in-service by mid-1997.
The Company must satisfy certain performance requirements as part of the
construction agreement. The initial performance warranty requires that the
gasifier attain an average capacity factor of 30% during 1997, regardless of
delays in the in-service date. If the gasifier does not achieve the 30% factor
required in 1997, the Company is required to pay liquidated damages to GECC
ranging from $93,000 to $2.8 million depending on the performance levels
achieved. The targeted capacity factor for 1998 is 70%. The liquidated damages
required to be paid by SPPC to The LLC if the 70% target is not met in 1998 are
shown in the table below:
<TABLE>
<CAPTION>
Certified Average Capacity Factor Liquidated Damages Owed by SPPC
- ------------------------------------ -------------------------------
<S> <C>
68% $ 1.5 million
66% $ 3.0 million
64% $ 4.5 million
62% $ 6.0 million
</TABLE>
If the capacity factor falls below 62% in 1998, an initial total
performance failure is triggered with appropriate liquidated damages to be paid
by the Company (up to a maximum of $33.0 million) and acquisition of the
gasifier facility by SPPC.
Under the continuing performance warranty, the average capacity factor is
recalculated for the five-year period ending December 31, 2003. If the five-
year average factor falls between 62% and 70%, liquidated damages will be
68
<PAGE>
assessed with a maximum exposure for SPPC of $10 million. If the five-year
average capacity factor or the average capacity factor for 2003 falls below 62%,
or if the factor is less than 50% in any of the years 1999-2002, SPPC is
required to purchase the facility and pay GECC an after-tax yield of 9.5% on its
investment.
Under the terms of the syngas purchase agreement, SPPC is required to
purchase from The LLC, at an already determined price, all syngas produced by
the facility, up to a 70% average capacity. The syngas contract runs from 1997
to 2012, with a right of early termination if the price is determined to be
uneconomic.
The Company believes the gasifier technology will achieve the required
capacity factors. If, however, the gasifier does not achieve the required
capacity factor and SPPC must acquire the facility, SPPC will benefit from the
partial funding by the DOE. The Company will have acquired a combined-cycle
combustion turbine power plant that can use natural gas or conventional fuels,
with minor modifications, as approved in the Nevada Resource Plan.
69
<PAGE>
NOTE 5. PREFERRED STOCK
- ------------------------
All issues of preferred stock are superior to the Company's and SPR's
common stock with respect to dividend payments (which are cumulative) and
liquidation rights. The Company'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>
1996 1995
-------------------- --------------------
(dollars in thousands) Shares Amount Shares Amount
--------- -------- --------- --------
<S> <C> <C> <C> <C>
Not Subject to
Mandatory Redemption:
Series A 80,500 $ 4,025 80,500 $ 4,025
Series B 82,000 4,100 82,000 4,100
Series C 299,800 14,990 299,800 14,990
Class A Series 1 2,000,000 50,000 2,000,000 50,000
--------- -------- --------- -------
Subtotal 2,462,300 73,115 2,462,300 73,115
Subject to Mandatory
Redemption:
Series G - - 408,000 20,400
Preferred Securities
of Sierra Pacific Power
Capital I 1,940,000 48,500 - -
--------- -------- --------- -------
Total 4,402,300 $121,615 2,870,300 $93,515
========= ======== ========= =======
</TABLE>
The Company's Series G Preferred Stock was redeemable at any time at a
current redemption price of $50 plus accrued dividends. SPPC was required to
redeem 136,000 shares at par value plus accrued dividends annually starting June
1, 1994. On June 3, 1996, the Company redeemed the remaining 408,000 shares of
Series G, 8.24% Preferred Stock, at par value, for $20.4 million using the
proceeds from the following issuance of Preferred Securities. As of December
31, 1995, 272,000 Series G shares had been redeemed.
On July 29, 1996, Sierra Pacific Power Capital I (the Trust), a wholly-
owned subsidiary of the Company, issued $48.5 million (1,940,000 shares) 8.60%
Trust Originated Preferred Securities (the Preferred Securities). The Company
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 the
Company its 8.60% Junior Subordinated Debentures due July 30, 2036, in a
principal amount of $50 million. The sole asset of the Trust is the Company's
Junior Subordinated Debentures. The Company's obligations under the Guarantee
Agreement entered into in connection with the Preferred Securities, when taken
together with the Company's obligation to make interest and other payments on
the Junior Subordinated Debentures issued to the Trust, and the Company's
obligations under its Indenture pursuant to which the Junior
70
<PAGE>
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 the Company of the Trust's
obligations under the Preferred Securities. In addition to retiring the Series G
Preferred Stock, proceeds were used to reduce short-term borrowings.
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
United States 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 the Company to the Trust on the Junior Subordinated
Debentures is not, or will not be, deductible, in whole or in part by the
Company 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 6. LONG-TERM DEBT
- -----------------------
Substantially all utility plant is subject to the lien of the indenture
under which the first mortgage bonds are issued. The indenture contains sinking
and improvement fund provisions which require the Company to make annual cash
deposits with the trustee equivalent to 1.75% or the greatest aggregate
principal amount of bonds of the respective series outstanding prior to a date
one and one-half months preceding the next sinking fund payment date, with
certain deductions allowable with respect to all bonds. The Company has
satisfied these requirements in past years by relinquishing the right to use a
net amount of additional property for bond issue, and expects to continue this
practice in the future.
A financing agreement in connection with the Company's $80 million Water
Facilities Bonds, maturing in 2020, requires the Company to maintain a bank
letter of credit agreement. On July 19, 1996, the Company converted the
interest rate on the bonds to a daily rate which reduced the letter of credit,
trustee fees, and administrative costs. The fees are included in long-term debt
interest charges on the Consolidated Statements of Income.
The Company issued $80 million of collateralized debt securities, Medium-
Term Notes, Series C. The Company issued $30 million principal amount of
Medium-Term Notes, Series C. These are ten year non-callable notes, due in
2006, with interest rates ranging from 6.62% to 6.83% and three year non-
callable notes, due in 1999, with interest rates ranging from 6.83% to 6.86%.
For all notes, interest is payable in semi-annual payments. The net proceeds
71
<PAGE>
to the Company from the sales of the notes were used to reduce short-term debt
and fund construction projects.
In December 1996, the Company registered an additional $35 million of
collateralized debt securities. The net proceeds to the Company from the sale
of these notes will be used for general corporate purposes including, but not
limited to: the acquisition of property; the construction, completion,
extension or improvement of facilities; or the refinancing or discharge or
refunding of obligations, including short-term borrowings.
The Company's aggregate annual amounts of maturities for long-term debt for
the next five years is shown below (dollars in millions):
<TABLE>
<CAPTION>
<S> <C>
1997 15.4
1998 .5
1999 30.4
2000 .3
2001 .2
</TABLE>
NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS
- --------------------------------------------
The December 31, 1996 and 1995 carrying amounts for cash, cash equivalents,
current assets, accounts payable, current liabilities, and construction trust
funds approximates fair value due to the short-term nature of these instruments.
The total fair value of the Company's long-term debt at December 31, 1996,
is estimated to be $619.1 million (excluding current portion) based on quoted
market prices for the same or similar issues or on the current rates offered to
the Company for debt of the same remaining maturities. The total fair value
(excluding current portion) was estimated to be $572.4 million at December 31,
1995.
NOTE 8. SHORT-TERM BORROWINGS
- ------------------------------
In 1995, the Company replaced its lines-of-credit arrangements with an $80
million revolving credit facility, which will expire on December 29, 1997. The
Company pays the lender a facility fee on the commitment quarterly, in arrears,
based on the Company's First Mortgage Bond rating; facility fees for 1996 and
1995 were approximately $101,000 for each year.
At December 31, 1996, the Company's short-term borrowings of $38.0 million
were comprised entirely of commercial paper at an average interest rate of
5.65%. At December 31, 1995, the Company had $56.0 million of commercial paper
at an average interest rate of 6.20%.
72
<PAGE>
NOTE 9. TAXES
- --------------
The following reflects the composition of taxes on income (dollars in
thousands):
<TABLE>
<CAPTION>
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
Federal:
Taxes estimated to be currently
payable $33,070 $39,150 $ 38,977
Deferred taxes related to:
Excess of tax depreciation over
book depreciation 5,217 9,237 10,693
Deferral of energy costs
deducted currently for tax
purposes-net (307) (4,112) (12,022)
Contributions in aid of
construction and customer
advances (2,917) (1,798) (4,835)
Avoided interest capitalized (3,124) (569) (1,744)
Costs of terminated merger 4,359 (776) -
Other - net (33) (2,739) 479
Net amortization of investment
tax credit (1,961) (1,942) (1,946)
State (California) 754 688 262
------- ------- --------
Total $35,058 $37,139 $ 29,864
======= ======= ========
As Reflected in
Consolidated Statements of Income:
Federal income taxes $35,487 $36,682 $ 28,851
State income taxes 754 688 262
------- ------- --------
Operating income 36,241 37,370 29,113
Other (expense) income-net
(1,183) (231) 751
------- ------- --------
Total $35,058 $37,139 $ 29,864
======= ======= ========
</TABLE>
73
<PAGE>
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 (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
Income before preferred dividends $ 73,651 $ 65,983 $60,863
Total income tax expense 35,058 37,139 29,864
-------- -------- -------
108,709 103,122 90,727
Statutory tax rate 35% 35% 35%
-------- -------- -------
Expected income tax expense 38,048 36,093 31,754
Depreciation related to
difference in cost basis
for tax purposes 471 2,394 2,805
Allowance for funds used
during construction - equity (1,831) (540) (715)
Tax benefit from the
disposition of assets (1,130) (1,427) (1,937)
ITC amortization (1,961) (1,942) (1,946)
Other-net 1,461 2,561 (97)
-------- -------- -------
$ 35,058 $ 37,139 $29,864
======== ======== =======
Effective tax rate 32.2% 36.0% 32.9%
======== ======== =======
</TABLE>
74
<PAGE>
Accumulated Deferred Federal Income Taxes
- -----------------------------------------
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 (dollars in thousands):
<TABLE>
<CAPTION>
December 31,
---------------------
1996 1995
--------- ---------
<S> <C> <C>
Accumulated Deferred Federal
Income Tax Liabilities:
Excess of tax depreciation
over book depreciation $142,441 $136,067
Tax benefits flowed
through to customers 67,667 69,610
Bond redemptions 6,690 7,184
AFUDC 5,745 4,459
Other 7,533 5,403
-------- --------
Total 230,076 222,723
-------- --------
Accumulated Deferred Federal
Income Tax Assets:
Avoided interest capitalized 12,241 9,117
Contributions in aid of
construction and customer advances 25,980 23,102
Unamortized investment tax credit 22,527 23,583
Other 6,890 7,949
-------- --------
Total 67,638 63,751
-------- --------
Net Accumulated Deferred Federal Income
Tax Liability $162,438 $158,972
======== ========
</TABLE>
The Company's balance sheets contain a net regulatory tax asset of $24.8
million at year-end 1996 and $24.5 million at year-end 1995. The net regulatory
asset consists of future revenue to be received from customers (a regulatory tax
asset) of $67.7 million at year-end 1996 and $69.6 million at year-end 1995, due
to the 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 $20.4 million at year-end 1996 and $21.5
million at year-end 1995, due to temporary differences for liberalized
depreciation at rates in excess of current tax rates, and $22.5 million at year-
end 1996 and $23.6 million at year-end 1995 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 manner as the accumulated
deferred investment credit.
75
<PAGE>
NOTE 10. DIVIDENDS
- -------------------
The Restated Articles of Incorporation of the Company 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 $72.5 million of retained earnings was
available at December 31, 1996 for the payment of common stock cash dividends.
NOTE 11. RETIREMENT PLAN
- -------------------------
The Company sponsors a noncontributory defined benefit retirement plan
covering all employees who satisfy the service requirement.
The 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.
The Company's funding policy 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 Company common or preferred stock.
In April 1995, the Company offered an early retirement plan to non-
bargaining unit employees 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, the Company began amortization of the
termination costs by recognizing expense for both 1995 and 1996. The Company is
using a ten-year amortization period for these costs which is consistent with
the treatment of previous early retirement programs.
76
<PAGE>
The following table sets forth a reconciliation of the funded status of the
plan with amounts included in the Company's consolidated balance sheets as of
December 31, 1996 and 1995 (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995
---------- ----------
<S> <C> <C>
Actuarial present value of benefit
obligations:
Vested benefit obligation $ 118,383 $ 119,495
========= =========
Accumulated benefit obligation $ 125,547 $ 127,276
========= =========
Projected benefit obligation $ 157,660 $ 165,877
Less plan assets at fair value (167,416) (148,436)
--------- ---------
Projected benefit obligation (less
than) in excess of plan assets (9,756) 17,441
Unrecognized net gain 26,661 5,715
Unrecognized prior service cost (4,251) (4,624)
--------- ---------
Net balance sheet liability $ 12,654 $ 18,532
========= =========
</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.
Net periodic pension expense for 1996, 1995 and 1994 included the following
components (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
Service cost $ 6,652 $ 6,320 $ 5,826
Interest cost 11,778 10,380 9,252
Actual (gain) loss on plan assets (19,954) (33,248) 4,986
Net amortizations and deferrals 7,736 23,518 (14,761)
Costs associated with 1995
early retirement plan - 12,825 -
-------- -------- --------
Net periodic pension cost as
determined under SFAS No. 87 6,212 19,795 5,303
Amount expensed (deferred) under
SFAS No. 71 - net 3,882 (11,509) 1,316
-------- -------- --------
Net periodic pension expense
recognized $ 10,094 $ 8,286 $ 6,619
======== ======== ========
Amount charged to operating expense $ 6,769 $ 5,416 $ 4,550
======== ======== ========
Amount charged to utility plant
and clearing accounts $ 3,325 $ 2,870 $ 2,069
======== ======== ========
</TABLE>
In the table above, 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.
77
<PAGE>
The amount deferred under SFAS No. 71 represents the SFAS No. 88 costs
arising from the 1989, 1992 and 1995 early retirement programs. Pursuant to
Nevada Commission directive and prior precedent, costs for the 1989, 1992 and
1995 programs are being amortized over 10 years and are summarized as follows
(dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
------- ---------- -------
<S> <C> <C> <C>
SFAS No. 88 costs associated with
the 1995 early retirement program $ - $(12,825) $ -
Amortization of 1995 early
retirement program 2,566
Amortization of 1992 early
retirement program 574 574 574
Amortization of 1989 early
retirement program 742 742 742
------ -------- ------
Net amount expensed (deferred)
under SFAS No. 71 $3,882 $(11,509) $1,316
====== ======== ======
</TABLE>
The weighted average discount rate used in determining the actuarial
present value of the projected benefit obligation as of December 31, 1996, 1995
and 1994 was 7.50%, 7.00% and 8.00%, respectively. For purposes of determining
1996, 1995 and 1994 pension cost, the expected long-term rate of return on
assets was 8.50%, 9.00% and 9.00%, respectively.
In addition to the employee retirement plan covering all employees, the
Company has a Supplemental Executive Retirement Plan which is a non-qualified
defined benefit plan under which the Company will pay out of general assets
supplemental pension benefits to key executives. The Company also has a non-
qualified supplemental pension plan covering certain employees. This plan
provides for incremental pension payments from the Company's funds so that total
pension payments equal amounts that would have been payable from the Company's
principal pension plan if it were not for limitations imposed by income tax
regulations. The unfunded liability under these plans as of December 31, 1996
and 1995 was $4.9 million and $4.8 million, respectively.
78
<PAGE>
NOTE 12. POSTRETIREMENT BENEFITS
- ---------------------------------
The Company currently sponsors a defined benefit postretirement plan that
covers administrative employees and those covered under collective bargaining
agreements. The plan provides medical, dental and life insurance benefits for
retirees. The 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.
The Company's funding policy for its postretirement benefit obligation
takes advantage of federal income tax deductions. Contributions are made to two
voluntary employee's beneficiary associations and an 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 Company common or preferred stock.
Postretirement health care costs for key executives continue to be paid from the
Company's general assets.
The following table sets forth a reconciliation of the funded status of the
plan with amounts included in the accompanying consolidated balance sheets as of
December 31, 1996 and 1995, (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995
--------- ---------
<S> <C> <C>
Accumulated postretirement benefit
obligation:
Retirees $ 37,941 $ 39,712
Fully eligible active participants 6,227 4,915
Other active plan participants 29,358 29,194
-------- --------
Total 73,526 73,821
Less plan assets at fair value (32,944) (25,076)
-------- --------
Accumulated postretirement benefit
obligation in excess of plan assets 40,582 48,745
Unrecognized prior service cost (415) --
Unrecognized net gain 8,562 3,340
Unrecognized transition obligation (39,419) (41,883)
-------- --------
Net balance sheet liability $ 9,310 $ 10,202
======== ========
</TABLE>
In the preceding table, unrecognized net gain represents the net change
attributed to changes in actuarial assumptions and differences between actual
experience and actuarial assumptions.
79
<PAGE>
Net periodic postretirement benefit expense for 1996, 1995 and 1994
included the following components (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
--------- -------- ---------
<S> <C> <C> <C>
Service cost $ 2,587 $ 2,448 $ 2,757
Interest cost 5,269 4,479 4,670
Actual (gain) loss on plan assets (1,942) (3,891) 313
Net amortizations and deferrals (94) 2,111 (962)
Amortization of transition
obligation over 20 years 2,464 2,838 2,785
Costs associated with 1995 early
retirement plan - 8,047 -
------- ------- -------
Net periodic postretirement benefit
cost determined under SFAS No. 106 8,284 16,032 9,563
Amount expensed (deferred) under
SFAS No. 71 - net 2,044 (7,086) 1,043
------- ------- -------
Net periodic postretirement expense
recognized $10,328 $ 8,946 $10,606
======= ======= =======
Amount charged to operating expense $ 6,903 $ 6,108 $ 7,102
======= ======= =======
Amount charged to utility plant and
clearing accounts $ 3,425 $ 2,838 $ 3,504
======= ======= =======
</TABLE>
In the table above 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.
The amount deferred under SFAS No. 71 for 1995 represents the present value
of termination benefits and curtailment losses resulting from the early
retirement and severance plans offered during that year. The present value of
these costs was originally recorded at $8.3 million during 1995, but was
revalued to $8.0 million during 1996 because of a revision in the measurement
date. These termination costs were fully deferred, as a regulatory asset, as of
December 31, 1995. Beginning in 1996, the Company began amortization of the
termination costs by recognizing expense for both 1995 and 1996. The Company is
using a ten-year amortization period for these costs which is consistent with
the treatment of previous early retirement programs.
80
<PAGE>
The amortization of 1993 deferred costs represents the annual amounts
expensed from charges initially deferred pending the decision of the general
rate case filed in December 1992. These costs were deferred as a result of a
regulatory phase-in plan which did not allow immediate recognition of these
costs when the Company adopted SFAS 106 in January 1993. As a result of the
decision, issued in June 1993, the Company began to amortize these costs over a
thirty-six month period beginning July 1993. The following schedule summarizes
the amortization of the deferred costs (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
------- --------- -------
<S> <C> <C> <C>
SFAS No. 106 costs deferred $ - $(8,047) $ -
Amortization of 1995 early
retirement program 1,610
Amortization of 1993 deferred costs 434 961 1,043
------ ------- ------
Net amount expensed (deferred) under
SFAS No. 71 $2,044 $(7,086) $1,043
====== ======= ======
</TABLE>
For measurement purposes, the Company used a discount rate for obligations
as of December 31, 1996, 1995 and 1994 of 7.50%, 7.00% and 8.00%, respectively.
The expected long-term return on assets was 8.50%, 9.00% and 9.00% for the same
periods, respectively. The graduated medical trend rates for 1996, 1995 and
1994 was 11.25%, 11.75% and 12.25%, respectively. This medical trend rate
declines by 0.50% over the next ten years to an ultimate rate of 5.75% in 2007,
remaining at that level thereafter. The health care cost trend rate has a
significant effect on the amounts reported. For example, an increase in the
health care cost trend rates by one percentage point in each year would increase
the accumulated postretirement benefit obligation as of December 31, 1996 by
$12.6 million and the aggregate of the service and interest cost component of
net periodic postretirement benefit cost for the year then ended by $1.7
million.
NOTE 13. POSTEMPLOYMENT AND OTHER BENEFITS
- -------------------------------------------
During 1995, the Company 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. Amortization of these
costs began in 1996 over a ten-year period consistent with the period used for
pension and postretirement benefits. There was no remaining liability for
unpaid severance and benefits at December 31, 1996. The remaining liability was
$3.0 million at December 31, 1995.
At December 31, 1996, the Company had several stock-based compensation
plans. The Executive Long-Term Incentive Plan for key management employees
allows for the issuance of SPR common shares to key employees through December
30, 2003. This plan permits the following types of grants, separately or in
combination: nonqualified and qualified stock options; stock appreciation
rights; restricted stock; performance units; performance shares and bonus stock.
81
<PAGE>
The Company also provides an Employee Stock Purchase Plan to all of its
employees meeting minimum service requirements. Employees can choose twice each
year to have up to 15% of their base earnings withheld to purchase SPR common
stock. The purchase price of the stock is 90% of the market value on the
offering date or 100% of the market price on the execution date, if less. The
Company records the costs of these plans in accordance with Accounting
Principles Board Opinion Number 25. There would be no material impact on net
income or earnings per share if the fair value provisions of SFAS 123 were to be
adopted.
NOTE 14. COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
The Company's estimated cash construction expenditures for the year 1997
and the five-year period 1997-2001 are $135.5 million and $605.4 million,
respectively.
Several of the Company's purchased power, gas supply and pipeline capacity,
and coal supply contracts contain minimum volume provisions, which the Company
is either meeting or exceeding. The Company anticipates continuing to meet or
exceed them in the future.
The Company 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 $5.2 million, which amount remains constant until the
end of the primary term. The lease has renewal options for an additional 50
years.
The total rental expense under all leases was approximately $8.2 million in
1996, $8.0 million in 1995 and $7.4 million in 1994.
Estimated future minimum lease commitments (including the corporate
headquarters building described above) under non-cancelable operating leases
with initial terms of one year or more at December 31, 1996 were as follows
(dollars in millions):
<TABLE>
<CAPTION>
<S> <C>
1997 $ 7.4
1998 7.2
1999 6.9
2000 6.4
2001 6.4
After 2001 to 2018 53.2
-----
Total $87.5
=====
</TABLE>
See Notes 5, 7 and 11 of the Company's consolidated financial statements
for additional commitments and contingencies.
82
<PAGE>
NOTE 15. SEGMENT INFORMATION
- -----------------------------
Information related to the segments of the Company's business is detailed
below (dollars in thousands):
<TABLE>
<CAPTION>
December 31, 1996 Electric Gas Water Total
- ------------------------- ---------- --------- --------- ----------
<S> <C> <C> <C> <C>
Operating Revenues $ 507,004 $ 67,376 $ 45,344 $ 619,724
========== ======== ======== ==========
Operating Income $ 86,428 $ 11,035 $ 9,545 $ 107,008
========== ======== ======== ==========
Depreciation Expense $ 47,797 $ 4,223 $ 6,098 $ 58,118
========== ======== ======== ==========
Capital Expenditures $ 158,482 $ 10,798 $ 33,829 $ 203,109
========== ======== ======== ==========
Identifiable Assets:
Net Utility Plant $1,182,623 $104,427 $256,160 $1,543,210
Other $ 141,956 $ 13,270 $ 12,653 $ 167,879
Other Corporate Assets - - - $ 131,539
----------
Total Assets - - - $1,842,628
==========
December 31, 1995 Electric Gas Water Total
- ----------------- ---------- -------- -------- ----------
Operating Revenues $ 491,419 $ 62,572 $ 43,793 $ 597,784
========== ======== ======== ==========
Operating Income $ 87,825 $ 5,041 $ 8,945 $ 101,811
========== ======== ======== ==========
Depreciation Expense $ 45,361 $ 4,019 $ 5,685 $ 55,065
========== ======== ======== ==========
Capital Expenditures $ 99,537 $ 13,318 $ 31,342 $ 144,197
========== ======== ======== ==========
Identifiable Assets:
Net Utility Plant $1,076,126 $ 98,367 $238,308 $1,412,801
Other $ 146,392 $ 11,505 $ 7,723 $ 165,620
Other Corporate Assets - - - $ 151,397
----------
Total Assets - - - $1,729,818
==========
December 31, 1994 Electric Gas Water Total
- ----------------- ---------- -------- -------- ----------
Operating Revenues $ 498,680 $ 65,174 $ 39,339 $ 603,193
========== ======== ======== ==========
Operating Income $ 81,641 $ 5,806 $ 8,536 $ 95,983
========== ======== ======== ==========
Depreciation Expense $ 43,137 $ 3,769 $ 5,270 $ 52,176
========== ======== ======== ==========
Capital Expenditures $ 91,483 $ 8,614 $ 25,381 $ 125,478
========== ======== ======== ==========
Identifiable Assets:
Net Utility Plant $1,026,602 $ 89,201 $215,675 $1,331,478
Other $ 117,888 $ 17,750 $ 7,573 $ 143,211
Other Corporate Assets - - - $ 131,021
----------
Total Assets - - - $1,605,710
==========
</TABLE>
83
<PAGE>
NOTE 16. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
- ----------------------------------------------------------
The following represents unaudited quarterly financial data (dollars in
thousands):
<TABLE>
<CAPTION>
Quarter Ended
------------------------------------------
Mar. 31, June 30, Sept 30, Dec. 31,
1996 1996 1996 1996
-------- -------- -------- ---------
<S> <C> <C> <C> <C>
(1)
Operating Revenues $162,154 $147,376 $158,682 $151,512
Operating Income $ 28,665 $ 23,180 $ 32,089 $ 23,074
Income Before Preferred
Dividends $ 20,114 $ 15,896 $ 23,482 $ 14,159
Income Applicable to
Common Stock $ 18,329 $ 14,391 $ 21,803 $ 12,828
<CAPTION>
Quarter Ended
------------------------------------------
Mar. 31, June 30, Sept 30, Dec. 31,
1995 1995 1995 1995
-------- -------- -------- --------
Operating Revenues $159,280 $138,782 $149,215 $150,507
Operating Income $ 26,764 $ 22,613 $ 26,564 $ 25,870
Income Before Preferred
Dividends $ 17,261 $ 13,579 $ 17,902 $ 17,241
Income Applicable to
Common Stock $ 15,336 $ 11,701 $ 16,116 $ 15,456
</TABLE>
(1) Reflects $13 million Nevada electric revenue refund.
84
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not Applicable
85
<PAGE>
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS OF THE REGISTRANT
(a) DIRECTORS
The following is a listing of all the current directors of the Company and
their ages as of December 31, 1996. There are no family relationships among
them. Directors serve staggered terms extending until May of each year and
until a successor has been elected and qualified.
Walter M. Higgins, 52
Chairman, President and Chief Executive Officer of the Company since
February 1994. He has been Chairman, President and Chief Executive Officer
of SPR since January 1994. Prior to assuming his current duties, Mr.
Higgins was President and Chief Operating Officer of SPR from November 1993
to January 1994. He served as President and Chief Operating Officer of
Louisville Gas and Electric Company from 1991 to November 1993. Mr.
Higgins held various executive positions with Portland General Electric
from 1977 to 1991. Mr. Higgins is also a director of Aegis Insurance
Services, Inc.
Edward P. Bliss, 64
Partner, Loomis, Sayles & Company, Inc., an investment counsel firm in
Boston, Massachusetts. He is also a Director of Seaboard Oil Company of
Midland, Texas. Mr. Bliss has served as Director of the Company since 1992
and as Director of SPR since 1990.
Krestine M. Corbin, 59
President and Chief Executive Officer of Sierra Machinery,
Incorporated since 1984 and a director of that company since 1980. She
also serves on the Twelfth Federal Reserve Bank District Board. Ms. Corbin
has served as a Director of the Company since 1992 and as Director of SPR
since 1989.
Theodore J. Day, 47
Senior Partner, Hale, Day, Gallagher Company, a real estate brokerage
and investment firm. Mr. Day has served as a Director of the Company since
1986 and Director of SPR since 1987.
Harold P. Dayton, Jr., 74
Retired President of Daytons' Furniture, Inc. Mr. Dayton has served
as a Director of the Company since 1967 and as Director of SPR since 1983.
86
<PAGE>
James R. Donnelley, 61
Vice Chairman of the Board of 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. He has been a Director of that Company since 1976.
He is also a Director of Pacific Magazines & Printing Limited and a
Director and Chairman of National Merit Scholarship Corporation. Mr.
Donnelley has served as a Director of the Company since 1992 and as a
Director of SPR since 1987.
Richard N. Fulstone, 69
President and General Manager of R.N. Fulstone Company since 1957 and
President and General Manager of F.M. Fulstone, Inc. since 1982. Both
companies engage in farming, cattle ranching and investments. Mr. Fulstone
has served as a Director of the Company since 1992 and as a Director of SPR
since 1986.
James L. Murphy, 67
Certified Public Accountant. 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 of the United States Air Force Reserve. Mr.
Murphy has served as a Director of the Company since 1990 and as Director
of SPR since 1992.
Ronald K. Remington, 54
President of Great Basin College since June 1989. He was previously
Vice President of Instruction at Truckee Meadows Community College. Mr.
Remington received his Ph.D. in psychology from the University of Nevada,
Reno. Mr. Remington has served as a Director since December 1991.
Dennis E. Wheeler, 54
Chairman, President and Chief Executive Officer of Coeur d'Alene Mines
Corporation since 1986. Mr. Wheeler has served as a Director of the
Company since 1992 and as a Director of SPR since 1990.
Robert B. Whittington, 70
Retired newspaper executive. Former President, Gannett West Newspaper
Group and Director, Gannett Company, Inc.; former publisher, Reno Gazette
and Nevada State Journal. Mr. Whittington has served as a Director of the
Company and SPR since 1985.
87
<PAGE>
All of the present Directors are Directors of Sierra Pacific Resources with
the exception of Dr. Remington. Messrs. Higgins and Murphy are Directors of
Lands of Sierra, Inc. (an affiliate of the Company); Messrs. Dayton and Higgins
are Directors of Sierra Gas Holding Company (an affiliate of the Company).
Messrs. Day and Higgins are Directors of Tuscarora Gas Pipeline Company (an
affiliate of the Company). Messrs. Fulstone and Higgins are Directors of Sierra
Water Development Company (an affiliate of the Company). Mr. Higgins is a
Director of Sierra Energy Company dba e.three, Tuscarora Gas Operating Company,
Pinon Pine Corp. and Pinon Pine Investment Co. (all are affiliates of the
Company).
88
<PAGE>
(b) EXECUTIVE OFFICERS
The following is a listing of all the current executive officers and their
ages as of December 31, 1996. 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.
Walter M. Higgins, 52, Chairman, President and Chief Executive Officer
See description under Item 10(a), Directors.
William E. Peterson, 49, Senior Vice President, General Counsel
and Corporate Secretary
Mr. Peterson was elected to his present position in January 1994. Mr.
Peterson holds the same position with Sierra Pacific Resources. 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 Sierra Pacific Resources since 1992. Mr.
Peterson was a partner in the Woodburn and Wedge Law Firm from 1982 to
1993.
Malyn K. Malquist, 44, Senior Vice President - Distribution Services Business
Group; Principal Operations Officer; Acting Chief
Financial Officer and Treasurer.
Mr. Malquist was elected to his present position in August 1996 and
holds the same position with Sierra Pacific Resources. Mr. Malquist was
Senior Vice President and Acting Chief Financial Officer and Treasurer for
the Company and Sierra Pacific Resources from August 1996 to February 1997.
Mr. Malquist was elected Senior Vice President and Chief Financial Officer
of SPR and the Company when he joined the Company in April 1994. He was
previously with San Diego Gas and Electric Company, where since 1978 he
held various financial positions, including Treasurer in 1990 and Vice
President in 1993.
Mark A. Ruelle, 35, Senior Vice President, Chief Financial Officer
and Treasurer
Mr. Ruelle was elected to his present position effective March 1, 1997
and holds the same position with Sierra Pacific Resources. Prior to joining
the Company, Mr. Ruelle was with Western Resources, Inc., where he held the
positions of President, Westar Energy in 1996; Vice President, Corporate
Development in 1995; and numerous positions in finance, treasury, strategic
planning, and regulatory affairs. Mr. Ruelle had been with Western
Resources, Inc., since 1986.
89
<PAGE>
Gerald W. Canning, 48, Vice President - Electric Production and Fuels Business
Mr. Canning was appointed to his present position in August 1996. He
has also served as President of Tuscarora Gas Pipeline Company since
February 1995. He was previously Vice President and General Manager -
Wholesale Energy Business from December 1995 to August 1996, Vice
President - Wholesale Electric Business from February 1994 to December
1995, Vice President - Electric Operations from December 1989 to February
1994, Vice President - Electric Resources from October 1987 to December
1989 and has been with the Company since 1968.
Randy G. Harris, 43, Vice President, Energy Marketing Services Business Group
Mr. Harris was appointed to his current position in November 1996. He
was previously General Manager, Transmission Services Business Group from
September 1996 to November 1996, Director of Wholesale Business from
December 1995 to September 1996, Director of Operations, Tuscarora Gas
Pipeline Company from October 1995 to December 1995 and Manager, Electric
Operations from February 1990 to October 1995. Mr. Harris has been with
the Company since 1974.
Lynn M. Miller, 48, Controller
Ms. Miller was appointed to her present position when she joined the
Company in August 1991 and elected to it in May 1992. Previously she was
with San Diego Gas and Electric for nine years, where she held various
accounting manager positions.
Steven C. Oldham, 46, Vice President - Transmission Business Group and
Strategic Development
Mr. Oldham was elected to his current position in November 1996. He
was previously Vice President - Strategic Development for the Company from
August 1996 to November 1996, Vice President - Information Resources,
Corporate Redesign and Merger Transaction from December 1995 to August
1996, Vice President - Regulation, and Treasurer from September 1994 to
December 1995, Treasurer and Director of Finance from May 1990 to September
1994, Manager of Economic and Financial Services from February to May 1990,
Manager of Corporate Budgets and Forecasts from April 1986 to February 1990
and has been with the Company since 1976.
Victor H. Pena, 48, Vice President - Technology, Information Services and
Business Development
Mr. Pena was elected to his present position in August 1996. He is
also Vice President of Business Development for Sierra Pacific Resources.
He was previously Vice President - Business Development and Treasurer from
December 1995 to August 1996, he was previously Vice President - Business
Development and Acting Treasurer from June 1994 to
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<PAGE>
December 1995. Since February 1995, he has served as President of Lands of
Sierra, Inc. Prior to joining the Company, he was Director of Financial
Planning and Budget with Louisville Gas and Electric Company from April
1991 to May 1994. From early 1990 to mid 1991, Mr. Pena was president and
owner of his own business, and from 1986 to 1990, was the Director of
Planning and Analysis of Kentucky Fried Chicken, a division of PepsiCo.
Mary Jane Willier, 50, Vice President, Human Resources
Ms. Willier was appointed 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,
the Company has 4 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 with respect to
the Company's preferred stock, which reports show no past or current beneficial
ownership of such preferred stock.
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<PAGE>
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth information about the compensation of the Chief
Executive Officer, 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
--------------------------------- --------------------------- --------
Securities
Other Under-
Annual Restricted lying
Name and Incentive Compen- Stock Options/ LTIP All Other
Principal Salary Pay sation Awards SARS Payouts Compensation
Position Year ($) ($) ($) ($) (#) ($) ($)
(a) (b) (c) (d) (3) (e) (4) (f) (g) (h) (5) (i) (6)
---------- ----- -------- ----------- -------- ------------ ------------ -------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Walter M. Higgins 1996 334,231 219,869 1,657 0 9,594 181,193 35,054
Chairman, President and Chief 1995 314,423 184,064 3,166 0 11,960 0 21,600
Executive Officer 1994 298,846 212,949 12,855 0 10,463 0 67,639
Malyn K. Malquist, (1) 1996 194,077 95,335 24,132 0 3,504 51,770 9,380
Senior Vice President, 1995 185,769 77,903 24,501 0 4,231 0 13,219
Distribution Services 1994 139,049 65,904 4,500 0 2,761 0 14,275
Business Group and Principal
Operations Officer, Sierra
Pacific Power Company;
Acting Chief Financial
Officer and Treasurer
William E. Peterson, 1996 191,923 85,445 3,417 0 3,504 70,508 20,982
Senior Vice President, 1995 190,000 77,903 6,157 0 4,231 0 14,876
General Counsel and 1994 190,000 89,384 9,660 0 3,758 0 12,568
Corporate Secretary
Gerald W. Canning 1996 147,692 46,232 1,423 0 2,066 38,602 14,350
Vice President, Electric 1995 139,769 46,510 5,600 0 2,570 0 9,252
Production and Fuels Business, 1994 130,975 53,603 314 0 2,059 0 8,278
Sierra Pacific Power Company
Victor H. Pena (2) 1996 133,639 39,775 5,677 0 1,694 20,877 6,770
Vice President, 1995 126,347 37,685 1,366 0 2,026 0 14,923
Business Development 1994 69,692 28,478 8,207 0 1,114 0 46,163
</TABLE>
Notes:
(1) Mr. Malquist became Senior Vice President, Distribution Services Business
Group & Principal Operations Officer for Sierra Pacific Power Company in
August 1996. He was hired in April 1994.
(2) Mr. Pena was hired May 1994. He is also Vice President, Technology,
Information Services, and Business Development for Sierra Pacific Power
Company.
(3) Amounts represent incentive pay received pursuant to SPR's "pay for
performance" team incentive plan.
(4) In accordance with the terms of his employment arrangement, the Company
discharged the annual installment due on Mr. Malquist's loan resulting in
other annual
92
<PAGE>
compensation of $23,000 to Mr. Malquist in 1996 and 1995. See Certain
Relationships and Related Transactions.
(5) LTIP Payouts relate to performance share payout pursuant to the Executive
Long-Term Incentive Plan approved by shareholders in 1994 for the three-year
period January 1, 1994 - December 31, 1996. Awards are based on attainment
of predetermined financial goals for annual growth in earnings per share and
overall shareholder return as compared to the Dow Jones Utility Index.
(6) Amounts of All Other Compensation include the following for 1996:
. Company contributions under the 401(K) Deferred Compensation Plan for all
administrative employees and the executive officers and directors, pursuant
to which the Company matches 50% of each executive officer's deferral up to
6% of salary. In 1996, the Company matching amount was $4,500 for Mr.
Higgins, $4,500 for Mr. Malquist, $4,500 for Mr. Peterson, $4,464 for Mr.
Canning, and $4,500 for Mr. Pena.
. The Company, in 1996, amended its Non-Qualified Deferred Compensation Plan
for its executive staff. Company contributions for Messrs. Higgins,
Malquist, Peterson, Canning and Pena were $21,062, $3,659, $11,041, $3,900,
and $1,184. The additional income on earnings contributed by the Messrs.
Higgins, Malquist, Peterson, Canning and Pena which was in excess of 120%
of the federal rate were $107, $63, $207, $319, and $18.
. Insurance premiums paid for split dollar life policies and the Company's
contribution and income earned from the Company's contribution toward
Executive Long Term Life Policies which replaced the split dollar life
policies in 1996 for Messrs. Higgins, Malquist, Peterson, Canning and Pena
were $6,006 and $3,379; $660 and $448; $992 and $4,242; $708 and $4,959;
$714 and $354, respectively.
. The Company, in 1996 instituted a Wellness Program designed to increase
awareness of personal health and fitness. All wishing to sign up were
encouraged to participate in a medical screening and as an incentive, $50
was paid by the Company. Mr. Malquist received $50 for participation in
the screening.
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<PAGE>
OPTIONS/SAR GRANTS IN LAST FISCAL YEAR
The following table shows all grants of options to the named executive
officers of Sierra Pacific Power Company in 1996. Pursuant to Securities and
Exchange Commission (the SEC) rules, the table also shows the present value of
the grant at the date of grant. The exercise price of all options is the market
value of the stock as listed on the New York Stock Exchange at the time the
options are granted.
<TABLE>
<CAPTION>
Individual Grants (1)
- ------------------------------------------------------------------------------------------------
Percent of
Total
Number of Options/SARS Grant
Securities Granted to Exercise Date
underlying Employees of Base Present
Options/SARS in Fiscal Price Expiration Value
Name Granted Year ($/Sh) Date ($)
(a) (b) (c) (d) (e) (f) (2)
- ---------------------- -------------------- ------------ -------- ---------- -------
<S> <C> <C> <C> <C> <C>
Walter M. Higgins 9,594 34.7% 23.375 1/1/06 23,985
Malyn K. Malquist 3,504 12.7% 23.375 1/1/06 8,760
William E. Peterson 3,504 12.7% 23.375 1/1/06 8,760
Gerald W. Canning 2,066 7.5% 23.375 1/1/06 5,165
Victor H. Pena 1,694 6.1% 23.375 1/1/06 4,235
</TABLE>
(1) Under the Executive Long-Term Incentive Plan, the grants of non-qualifying
stock options were made on January 1, 1996. Twenty percent of these grants
vest annually commencing one year after the date of the grant.
(2) The hypothetical grant date present values are calculated under a modified
Black-Scholes Model. The Black-Scholes Model is a mathematical formula used
to value options traded on stock exchanges. The assumptions used in
determining the option grant date present value listed above include the
stock's expected volatility (11.4%), risk free rate of return (6.5%),
projected dividend yield (5.3%), per annum for unvested options, the stock
option term (10 years), and an adjustment for non-transferability or risk of
forfeiture during the vesting period (5 years at 3%).
94
<PAGE>
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FY-END OPTION/SAR VALUES
The following table provides information as to the value of the options
held by the named executive officers at year-end measured in terms of the
closing price of Sierra Pacific Resources Common Stock on December 31, 1996.
<TABLE>
<CAPTION>
Number of
Securities Value of
Underlying Unexercised in-
Unexercised the-Money
Options/SARS Options/SARS at
Shares at Fiscal Fiscal Year-End
Acquired Year-End Exercisable/
on Value Exercisable/ Unexercisable
Name Exercise Realized Unexercisable ($)
(a) (b) (c) (d) (e)
- ----------------------------- ---------------------- --------------- --------------------------- --------------------------
<S> <C> <C> <C> <C>
Walter M. Higgins 0 0 6,577 / 25,440 58,448/199,040
Malyn K. Malquist 0 0 1,950 / 8,546 17,573/66,349
William E. Peterson 0 0 2,349 / 9,144 20,863/71,284
Gerald W. Canning 0 0 1,338 / 5,357 11,935/41,857
Victor H. Pena 0 0 850 / 3,984 7,728/30,828
</TABLE>
(e) Pre-tax gain. Value of in-the-money options based on December 31, 1996
closing trading price of $28.750 less the option exercise price.
95
<PAGE>
LONG-TERM INCENTIVE PLANS - AWARDS
IN LAST FISCAL YEAR
The Executive Long-Term Incentive Plan (the LTIP) provides for the granting
of stock options (both nonqualified and qualified), stock appreciation rights
(SAR's), 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 the Company. Goals are established for total shareholder return (TSR)
compared against the Dow Jones Utility Index and annual growth in earnings per
share (EPS).
The following table provides information as to the performance shares
granted to the named executive officers of Sierra Pacific Power Company in 1996,
which can be earned based on the attainment of established financial goals.
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>
Performance
Number of or Other Estimated Future Payouts Under
Shares, Period Non-Stock Price-Based Plans
Units or Until --------------------------------------------------------
Other Maturation Threshold Target Maximum
Name Rights or Payout $ $ $
(a) (b) (c) (d) (1) (e) (2) (f) (3)
- ----------------------------- ----------------- -------------------- ------------------- --------------- ----------------
<S> <C> <C> <C> <C> <C>
Walter M. Higgins 2,952 3 years 34,501 69,003 120,755
William E. Peterson 1,168 3 years 13,651 27,302 47,778
Malyn K. Malquist 1,168 3 years 13,651 27,302 47,778
Gerald W. Canning 689 3 years 8,053 16,105 28,184
Victor H. Pena 565 3 years 6,603 13,207 23,112
</TABLE>
(1) The threshold represents the level of TSR and EPS achieved during the cycle
which represents minimum acceptable performance and which, if attained,
results in payment of 50% of the target award. Performance below the minimum
acceptable level results in no award earned.
(2) The target represents the level of TSR and EPS achieved during the cycle
which indicates outstanding performance and which, if attained, results in
payment of 100% of the target award.
(3) The maximum represents the maximum payout possible under the plan and a
level of TSR and EPS indicative of exceptional performance which, if
attained, results in a payment of 175% of the target award.
All levels of awards are made with reference to the price of each
performance share at the time of grant.
96
<PAGE>
PENSION 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>
Highest Average Five- Annual Benefits for Years of Service Indicated
Years Remuneration 15 Years 20 Years 25 Years 30 Years 35 Years
- ------------------------ -------- -------- -------- -------- --------
<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.
Years of credited service under the qualified plan for Messrs. Higgins,
Malquist, Peterson, Canning, and Pena are 3.1, 2.7, 3.6, 27.1, and 2.6,
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.
In addition, 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 the Company, and an additional one-half year credit for each year of
service with the Company for the first ten years of his employment. The Company
also entered into an agreement with Mr. Pena when he accepted employment with
Sierra Pacific Resources after several years with Louisville Gas and Electric
Company, crediting him with three years of service.
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<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Voting Stock of SPR
The following table indicates the shares owned by Weiss Asset Management
Co., the only person known to Sierra Pacific Resources to be owner of more than
5 percent of any class of its voting stock as of February 28, 1997:
<TABLE>
<CAPTION>
Shares
Name and Address Beneficially Percent
Title of Class of Beneficial Owner Owner of Class
- ----------------- ------------------------ ------------ ---------
<S> <C> <C> <C>
Common Stock Weiss Asset Management 1,635,000 5.31 %
660 Madison Avenue
New York, NY 10022-8405
</TABLE>
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
Name of Director Owned as of Shares Outstanding as of
or Nominee February 28, 1997 February 28, 1997
- ------------------------ ----------------- ------------------------
<S> <C> <C>
Edward P. Bliss 11,557
Krestine M. Corbin 8,484
Theodore J. Day 18,054
Harold P. Dayton, Jr. 10,659
James R. Donnelley 15,496 No director or nominee
Richard N. Fulstone 12,833 for director owns in
Walter M. Higgins 17,386 excess of one percent.
James L. Murphy 8,331
Ronald K. Remington 6,170
Dennis E. Wheeler 7,342
Robert B. Whittington 11,047
-------
127,359
=======
</TABLE>
98
<PAGE>
<TABLE>
<CAPTION>
Common Shares
Beneficially Percent of Total Common
Owned as of Shares Outstanding as of
Executive Officers February 28, 1997 February 28, 1997
- ---------------------------------- ----------------- ------------------------
<S> <C> <C>
Walter M. Higgins 17,386
Malyn K. Malquist 6,656 No executive officer
William E. Peterson 6,208 owns in excess of one
Gerald W. Canning 8,008 percent.
Victor H. Pena 2,544
-------
40,802
-------
All directors and executive
officers as a group (a) (b) (c) 163,004
=======
</TABLE>
(a) Includes shares acquired through participation in the Employee Stock
Ownership Plan and/or Employee Stock Purchase 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. Shares beneficially owned pursuant to stock options granted
to Messrs. Higgins, Malquist, Peterson, Canning, and Pena, and all directors
and executive officers as a group are 12,979, 4,048, 4,646, 2,676, 1,816,
and 30,249 shares, respectively. Shares beneficially owned as a result of
performance shares earned by Messrs. Higgins, Malquist, Peterson, Canning,
Pena, and all directors and officers as a group are 3,400, 1,090, 1,435,
839, 400, and 9,139, respectively.
(c) Included in the shares beneficially owned by the Directors are 66,571 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.
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<PAGE>
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------
SPR has entered into 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 Wedge, which has performed legal services for Sierra Pacific
Power Company since 1920 and for Sierra Pacific Resources and all 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, was
moved to inactive status in the firm as of January 1, 1997.
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 resource area for
the Company on a contract basis.
In April 1994, Mr. Malquist, Senior Vice President and Chief Financial
Officer, 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 and will be discharged by the Company in
consideration for services rendered during the previous year.
CHANGE IN CONTROL AGREEMENT
---------------------------
The Company has entered into severance agreements with all of the executive
officers identified in Item 11, including the individuals named in the Summary
Compensation Table, and two other senior executives of the Company who are not
officers. These agreements provide that, upon termination of the executive's
employment within twenty-four months following a change in control of the
Company (as defined in the agreements) either (a) by the Company for reasons
other than cause (as defined in the agreements), death or disability, or (b) by
the executive for good reason (as defined in the agreement, including a
diminution of responsibilities, compensation, or benefits (unless, with respect
to reduction in salary or benefits, such reduction is applicable to all senior
executives of 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 he continued to participate in the
Company's retirement plans for an additional 3 years (or,
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<PAGE>
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. The agreements also provide that if any compensation paid, or
benefit provided, to the executive, whether or not pursuant to the severance
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.
101
<PAGE>
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 Accountants............................... 55
Consolidated Balance Sheets as of
December 31, 1996 and 1995.................................... 57
Consolidated Statements of Income for the Years
Ended December 31, 1996, 1995 and 1994........................ 58
Consolidated Statements of Common Shareholder's Equity
for the Years Ended December 31, 1996, 1995 and 1994.......... 59
Consolidated Statements of Capitalization as of
December 31, 1996 and 1995.................................... 60
Consolidated Statements of Cash Flows for the
Years Ended December 31, 1996, 1995 and 1994.................. 61
Notes to Consolidated Financial Statements...................... 62
</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 105-114.
(B) REPORTS ON FORM 8-K
Filed on November 20, 1996 - Item 4, Changes in Registrant's
Certifying Accountant
Based upon the recommendation if its audit committee, the Board of
Directors of the Company, a wholly owned subsidiary of Sierra Pacific
Resources, voted to appoint Deloitte & Touche LLP as the Company's
independent accountants. Coopers & Lybrand L.L.P. had previously served as
the Company's independent accountants. During the two most recent fiscal
years, ending December 31, 1995, the reports on financial statements by
Coopers & Lybrand L.L.P. did not contain any adverse opinion or disclaimer
of opinion, nor were the reports modified or qualified in any manner.
Additionally, there were no disagreements with Coopers & Lybrand L.L.P. on
any matter of accounting principle or practice, financial statement
disclosure or auditing scope or procedure for the above mentioned period
nor were there any "reportable events" as defined in Item 304 (a) (1) (v)
of Regulation S-K.
102
<PAGE>
Reports on Form 8-K/A
Filed on November 22, 1996 - Amendment of Form 8-K filed on November 20,
1996
. To include as an exhibit a letter from Coopers & Lybrand L.L.P. dated
November 21, 1996 regarding the change in certifying accountants.
103
<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/ Walter M. Higgins
---------------------------------
Walter M. Higgins
Chairman, President and
Chief Executive Officer
March 21, 1997
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 21st day of March, 1997.
/s/ Mark A. Ruelle /s/ Lynn M. Miller
- ------------------------------ -----------------------------
Mark A. Ruelle Lynn M. Miller
Senior Vice President and Controller
Chief Financial Officer (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/ Walter M. Higgins
- --------------------------------- ------------------------------
James R. Donnelley Walter M. Higgins
Director Director
/s/ Richard N. Fulstone
- --------------------------
Richard N. Fulstone
Director
104
<PAGE>
SIERRA PACIFIC POWER COMPANY
1996 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.
A (1)
. Distribution Agreement related to the Company's offering of $35
million of Collateralized Medium-term Notes, Series D. (Exhibit A on
Form 8-K dated March 10, 1997).
(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)
. Articles of Incorporation of Pinon Pine Corp., dated December 11,
1995. (Exhibit (3) (A) to Form 10-K filed December 31, 1995)
. Articles of Incorporation of Pinon Pine Investment Co., dated
December 11, 1995. (Exhibit (3) (B) to Form 10-K dated December 31,
1995)
. 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. (Exhibit (3) (C) to Form 10- K
dated December 31, 1995)
105
<PAGE>
(3) - CONTINUED
*(A)
By-laws of the Company, in its entirety as amended through November
13, 1996.
(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. 33-69550); Thirty-Third
Supplemental Indenture (Exhibit C to Form 8-K dated October 20, 1993
in connection with the Company's medium-term note program); Thirty-
fourth Supplemental Indenture (Exhibit C to Form 10-K dated February
1, 1996 in connection with the Company's medium-term note program)
. Thirty-fifth Supplemental Indenture dated as of February 1, 1997 to
Indenture of Mortgage dated as of December 1, 1940 defining the
rights of the Company's First Mortgage Bonds. (Exhibit C of Form 8-K
dated March 10, 1997).
. 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)
106
<PAGE>
(4) - CONTINUED
. 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)
. 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 Series C. (Exhibit B to Form 8-K
dated March 11, 1996).
. Fourth Supplemental Indenture dated as of February 1, 1997 to
Collateral Trust Indenture dated as of June 1, 1992 between the
Company and Banker's Trust Company, as Trustee, relating to the
Company's medium-term note Program, Series D. (Exhibit B of Form 8-K
dated March 10, 1997).
. 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)
. Form of medium-term global floating rate note, Series C. (Exhibit D
to Form 8-K dated March 10, 1997).
. Form of Medium Term Global Fixed Rate Note, Series D. (Exhibit D of
Form 8-K dated March 10, 1997).
. 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).
107
<PAGE>
(4) - CONTINUED
. 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).
(10)
. Interconnection Agreement dated May 19, 1971 between the Company and
Utah Power & Light Company (originally filed as Exhibit (10)(D) to
the 1986 Form 10-K - refiled as Exhibit (10)(A) to the 1992 Form
10-K)
. Amendment dated September 12, 1977 to Interconnection Agreement
dated May 19, 1971 between the Company and Utah Power & Light
Company (Exhibit 5-T to Registration No. 2-62476)
. Second Amendment dated September 3, 1985 to Interconnection
Agreement dated May 19, 1971 between the Company and Utah Power &
Light Company (originally filed as Exhibit (10)(A) to the 1985 Form
10-K - refiled as Exhibit (10)(A) to the 1991 Form 10-K)
. 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)
108
<PAGE>
10 - CONTINUED
. 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)
. Firm Natural Gas Sale and Purchase Agreement (Petro I Agreement)
dated November 1, 1992 between the Company and Petro-Canada (Exhibit
(10)(E) to the 1992 Form 10-K; confidential portions omitted and
filed separately with the Securities and Exchange Commission)
. Firm Natural Gas Sale and Purchase Agreement (Petro II Agreement)
dated November 1, 1994 between the Company and Petro-Canada (Exhibit
(10)(F) to the 1992 Form 10-K; confidential portions omitted and
filed separately with the Securities and Exchange Commission)
. Short-Term Gas Sale and Purchase Agreement dated October 23, 1991
between the Company and Shell Canada Limited (Exhibit (10)(G) 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)
. Long-Term Power Sales Agreement dated February 9, 1989 between the
Company and PacifiCorp (Exhibit (10)(B) 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)
109
<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)
. North Valmy Station Operating Procedures Criteria dated July 1, 1986
between the Company and Idaho Power Company (originally filed as
Exhibit (10)(B) to the 1987 Form 10-K - refiled as Exhibit (10)(B)
to the 1993 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)
110
<PAGE>
(10) - CONTINUED
. 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)
. 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)
111
<PAGE>
(10) - CONTINUED
. Credit Agreement dated January 3, 1995 by and among the Company, The
Lenders Parties thereto 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)
. 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)
. Employment Agreement dated June 27, 1994 by and among the Company
SPR and Gerald C. Canning. (Exhibit (10)(C) 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.
. Fixed-Price Turn-Key Construction Agreement, dated December 15, 1995
between the Company and Pinon Pine Co., L.L.C.
. Operation and Maintenance Agreement, dated December 15, 1995 between
the Company and Pinon Pine Co., L.L.C.
. Syngas Purchase Agreement, dated December 15, 1995 between the
Company and Pinon Pine Co., L.L.C.
112
<PAGE>
(11)
. The Company is a wholly-owned subsidiary and, in accordance with
Paragraph 6 of Accounting Principles Board Opinion No. 15 (Earnings
Per Share), earnings per share data have been omitted.
(12)
. Calculation of Ratio of Earnings to Fixed Charges used in connection
with the Company's Registration Statement (No. 333-17041) relating
to its offering of $35 million of Collateralized medium-term notes,
Series D. (Exhibit E to Form 8-K dated March 10, 1997).
*(A)
Calculation of Pre-Tax Interest Coverages for the Periods 1996,
1995, and 1994.
(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 Corp.
Pinon Pine Investment Co.
Sierra Pacific Power Capital Trust I (The Trust)
(23) *(A)
Consent of Independent Accountants, Deloitte and Touche, LLP, Form
S-3 of Sierra Pacific Power Company for Series D medium-term notes
(File No. 333-17041).
*(B)
Consent of Independent Accountants Coopers and Lybrand L.L.P., Form
S- 3 of Sierra Pacific Power Company for Series D medium-term notes
(File No. 333-17041).
113
<PAGE>
(27)
. The Financial Data Schedule containing summary financial information
extracted from the consolidated financial statements of the Company
used in connection with the Form 10-Q for the six-month period
ending June 30, 1996. (Exhibit filed with the Form 10-Q dated August
14, 1996).
. The Financial Data Schedule containing summary financial information
extracted from the consolidated financial statements of the Company
used in connection with the Form 10-Q for the nine-month period
ended September 30, 1996. (Exhibit filed with the Form 10-Q dated
November 7, 1996).
*(A)
The Financial Data Schedule containing summary financial information
extracted from the consolidated financial statements filed on Form
10- K for the twelve month period ending December 31, 1996. (Exhibit
filed with the Form 10-K dated March 14, 1997.)
(99)
. Press Release from the Company dated June 28, 1996 announcing
receipt of notification from its merger partners, Spokane-based
Washington Water Power Company (WWP), that WWP no longer intends to
pursue the merger of the two companies. (Exhibit C of Form 8-K dated
July 3, 1996).
_______________________________________________
114
<PAGE>
(3) (A)
BY-LAWS
OF
SIERRA PACIFIC POWER COMPANY
formerly
Sierra Nevada Power Company
(Adopted: January 15, 1965)
(Amended: May 19, 1969)
(Amended: April 23, 1970)
(Amended: May 19, 1975)
(Amended: July 1, 1975)
(Amended: May 19, 1980)
(Amended: September 15, 1981)
(Amended: May 21, 1984)
(Amended: June 30, 1988)
(Amended: June 24, 1994)
(amended: November 13, 1996)
<PAGE>
ARTICLE I
NAME
----
The name of the Corporation (hereinafter referred to as this
Corporation) shall be as set forth in the Articles of Incorporation or in any
lawful amendments thereto from time to time.
ARTICLE II
STOCKHOLDERS' MEETINGS
----------------------
All meetings of the stockholders shall be held at the principal office
of the Corporation in the State of Nevada unless some other place within or
without the State of Nevada is stated in the call. No stockholder action
required to be taken or which may be taken at any annual or special meeting of
stockholders of the Corporation may be taken without a meeting, and the power of
stockholders to consent in writing without a meeting to the taking of any action
is specifically denied.
ARTICLE III
ANNUAL STOCKHOLDERS' MEETINGS
-----------------------------
The Annual Meeting of the Stockholders of the Corporation shall be
held at such time and place as directed or selected by a majority of the Board
of Directors.
ARTICLE IV
SPECIAL STOCKHOLDERS' MEETINGS
------------------------------
Special meetings of the stockholders of this Corporation shall be held
whenever called in the manner required by law for the purpose as to which there
are special statutory provisions and for other purposes whenever called by the
Chairman of the
1
<PAGE>
Board, the President, a Vice President or by a quorum of the Board of Directors
or whenever the holder or holders of at least one-third part in voting power of
the capital stock entitled to vote shall make written application therefor to
the Secretary or an Assistant Secretary stating the time, place and purpose of
the meeting applied for.
ARTICLE V
NOTICE OF STOCKHOLDERS' MEETINGS
--------------------------------
Notice stating the place, day and hour of all stockholders' meetings
and the purpose or purposes for which such meetings are called, shall be given
by the President or a Vice President or the Secretary or an Assistant Secretary
not less than ten (10) nor more than sixty (60) days prior to the date of the
meeting to each stockholder entitled to vote thereat by leaving such notice with
him at his residence or usual place of business, or by mailing it, postage
prepaid, addressed to such stockholder at his address as it appears upon the
books of this Corporation, and to the Chairman of the Board at the Corporation's
main office, the person giving such notice shall make affidavit in relation
thereto.
2
<PAGE>
ARTICLE VI
QUORUM AT STOCKHOLDERS' MEETINGS
--------------------------------
Except as otherwise provided by law, at any meeting of the
stockholders, a majority of the voting power of the shares of capital stock
issued and outstanding and entitled to vote, represented by such stockholders of
record in person or by proxy, shall constitute a quorum, but a less interest may
adjourn any meeting sine die or adjourn any meeting from time to time and the
meeting may be held as adjourned without further notice. When a quorum is
present at any meeting, a majority of the voting power of the stock entitled to
vote represented thereat shall decide any question brought before such meeting,
unless the question is one upon which by express provision of law, or of the
Articles of Incorporation, or of these By-Laws a larger or different vote is
required, in which case such express provision shall govern and control the
decision of such question.
ARTICLE VII
PROXY AND VOTING
----------------
Stockholders of record entitled to vote may vote at any meeting either
in person or by proxy in writing, which shall be filed with the Secretary of the
meeting before being voted. Such proxies shall entitle the holders thereof to
vote at any adjournment of such meeting, but shall not be valid after the final
adjournment thereof. No proxy shall be valid after the expiration of six (6)
months from the date of its execution unless the stockholder specifies therein
the length of time for which it is to continue in force, which in no case shall
exceed seven (7) years from the date of its execution. Stockholders entitled to
vote shall be entitled to the voting rights as provided in the Articles of
Incorporation.
3
<PAGE>
ARTICLE VIII
BOARD OF DIRECTORS
------------------
A Board of not less than three (3) nor more than fifteen (15)
Directors shall be chosen at the Annual Meeting of the Stockholders, or at any
meeting held in place thereof as hereinbefore provided. The number of Directors
for each corporate year shall be fixed by resolution or vote at the meeting when
elected, but the Stockholders, at a Special Meeting held for the purpose during
any such year, may increase or decrease (within the limits above specified) the
number of Directors as thus fixed. If the number of Directors be increased at
any such Annual or Special Meeting of Stockholders, the additional Directors may
be elected by the Stockholders at such meeting, or in the event that the
Stockholders shall fail to elect such additional Directors at such meeting, such
additional Directors may be elected by a majority of the Directors in office at
the time of the increase. Except as otherwise provided in these By-Laws, each
Director shall serve until the next Annual Meeting of the Stockholders and until
his successor is duly elected and qualified. Directors need not be Stockholders
in the Corporation. Directors shall be of full age and at least one of them
shall be a citizen of the United States.
4
<PAGE>
ARTICLE IX
POWERS OF DIRECTORS
-------------------
The Board of Directors shall have the entire management of the
business of this Corporation. In the management and control of the property,
business and affairs of this Corporation, the Board of Directors is hereby
vested with all the powers possessed by this Corporation itself, so far as this
delegation of authority is not inconsistent with the laws of the State of
Nevada, with the Articles of Incorporation or with these By-Laws. Except as
otherwise provided by law, the Board of Directors shall have power to determine
what constitutes net earnings, profits and surplus, respectively, what amount
shall be reserved for working capital and for any other purposes, and what
amount shall be declared as dividends, and such determination by the Board of
Directors shall be final and conclusive.
ARTICLE X
COMPENSATION OF DIRECTORS AND OTHERS
------------------------------------
Directors may be compensated for their services on an annual basis
and/or they may receive a fixed sum plus expenses of attendance, if any, for
attendance at each Regular or Special Meeting of the Board, such compensation or
fixed sum to be fixed from time to time by resolution of the Board of Directors,
provided that nothing herein contained shall be construed to preclude any
director from serving this Corporation in any other capacity and receiving
compensation therefor. Members of special or standing committees may receive
like compensation for their services on an annual basis and/or fixed sum for
attendance at each committee meeting. Any compensation so fixed and determined
by the Board of Directors shall be subject to revision or amendment by the
stockholders.
5
<PAGE>
ARTICLE XI
EXECUTIVE AND OTHER COMMITTEES
------------------------------
The Board of Directors may, by resolution or vote passed by a majority
of the whole Board, designate from their number an Executive Committee of not
less than three (3) nor more than a majority of the members of the whole Board
as at the time constituted, which Committee shall have and may exercise the
powers of the Board of Directors in the management of the business and affairs
of this Corporation when the Board is not in session. The Executive Committee
may make rules for the notice, holding and conduct of its meetings and keeping
of the records thereof. Such Committee shall serve until the first Directors'
meeting following the next Annual Stockholders' Meeting, and until their
successors shall be designated and shall qualify, and a majority of the members
of said Committee shall constitute a quorum for the transaction of business.
The Board of Directors shall, by resolution or vote passed by a
majority of the whole Board, designate from their members who are not employees
of the Corporation to serve on an Audit Committee of not less than three (3) nor
more than a majority of the whole Board at the time constituted, to nominate
auditors for the annual audit of the Corporation's books and records, to develop
the scope of the audit program, to discuss the results of such audits with the
audit firm, and to take any other action they may deem necessary or advisable in
carrying out the work of the Committee. Such Committee shall serve until their
successors shall be designated and shall qualify, and a majority of the members
of the Audit Committee shall constitute a quorum for the transaction of
business.
The Board of Directors may also appoint other committees from time to
time, the number composing such committees, and the powers conferred upon the
same to be
6
<PAGE>
determined by resolution or vote of the Board of Directors.
ARTICLE XII
DIRECTORS' MEETINGS
-------------------
Regular meetings of the Board of Directors shall be held at such
places within or without the State of Nevada and at such times as the Board by
resolution or vote may determine from time to time, and if so determined no
notice thereof need be given. Special meetings of the Board of Directors may be
held at any time or place within or without the State of Nevada whenever called
by the Chairman of the Board, the President, a Vice President, a Secretary, an
Assistant Secretary or two or more Directors, notice thereof being given to each
Director by the Secretary, an Assistant Secretary or officer calling the
meeting, or at any time without formal notice provided all the Directors are
present or those not present waive notice thereof. Notice of Special Meetings,
stating the time and place thereof, shall be given by mailing the same to each
Director at his residence or business address at least two days before the
meeting, unless, in case of exigency, the President or in his absence the
Secretary shall prescribe a shorter notice to be given personally or by
telephoning or telegraphing each Director at his residence or business address.
Such Special Meetings shall be held at such times and places as the notices
thereof or waiver shall specify.
Meetings of the Board of Directors may be conducted by means of a
conference telephone network or a similar communications method by which all
persons participating in the meeting can hear each other. The minutes of such
meeting shall be submitted to the Board of Directors, for approval, at a
subsequent meeting.
7
<PAGE>
Unless otherwise restricted by the Articles of Incorporation or these
By-Laws, any action required or permitted to be taken at any meeting of the
Board of Directors or of any committee thereof may be taken without a meeting if
a written consent thereto is signed by all the members of the Board of Directors
or of such committee. Such written consent shall be filed with the minutes of
meetings of the Board or Committee.
ARTICLE XIII
QUORUM AT DIRECTORS' MEETING
----------------------------
Except as otherwise provided by law, by the Articles of Incorporation,
or by these By-Laws, a majority of the members of the Board of Directors shall
constitute a quorum for the transaction of business, but a lesser number may
adjourn any meeting from time to time, and the meeting may be held as adjourned
without further notice. When a quorum is present at any meeting, a majority of
the members present thereat shall decide any question brought before such
meeting.
ARTICLE XIV
WAIVER OF NOTICE
----------------
Whenever any notice whatever of any meeting of the stockholders, Board
of Directors or any committee is required to be given by these By-Laws or the
Articles of Incorporation of this Corporation or any of the laws of the State of
Nevada, a waiver thereof in writing, signed by the person or persons entitled to
said notice whether before or after the time stated therein, shall be deemed
equivalent to such notice so required. The presence at any meeting of a person
or persons entitled to notice thereof shall be deemed a waiver of such notice as
to such person or persons.
8
<PAGE>
ARTICLE XV
OFFICERS
--------
The officers of this Corporation shall be a President, one or more
Vice Presidents, a Secretary, a Controller, and a Treasurer. The Board of
Directors at its discretion may elect a Chairman of the Board of Directors. The
Chairman of the Board of Directors, if one is to be elected, the President, the
Vice Presidents, the Secretary, the Controller, and the Treasurer shall be
elected annually by the Board of Directors after its election by the
stockholders and shall hold office until their successors are duly elected and
qualified, subject, however, to other provisions contained in these By-Laws, and
a meeting of the Directors may be held without notice for this purpose
immediately after the Annual Meeting of the Stockholders and at the same place.
ARTICLE XVI
ELIGIBILITY OF OFFICERS
-----------------------
Any two or more offices may be held by the same person except the
offices of Chairman of the Board of Directors or President and Secretary shall
not be held by the same person.
The Chairman of the Board of Directors and the President may, but need
not, be Stockholders and shall be Directors of the Corporation. The Vice
Presidents, Secretary, Treasurer and such other officers as may be elected or
appointed need not be stockholders or Directors of this Corporation.
ARTICLE XVII
ADDITIONAL OFFICERS AND AGENTS
------------------------------
9
<PAGE>
The Board of Directors, at its discretion, may appoint one or more
Assistant Secretaries and one or more Assistant Treasurers and such other
officers or agents as it may deem advisable, and prescribe their duties. All
officers and agents appointed pursuant to this Article may hold office during
the pleasure of the Board of Directors.
ARTICLE XVIII
CHAIRMAN OF THE BOARD AND PRESIDENT
-----------------------------------
(A) Chairman of the Board: The Chairman of the Board shall preside
---------------------
at all meetings of the shareholders and the Board of Directors and shall have
such powers and perform such other duties as may be assigned to him from time to
time by the Board of Directors, including, but not limited to, the signing or
countersigning of certificates of stock, bonds, notes, contracts or other
instruments of the Corporation as authorized by the Board of Directors. He
shall be ex-officio a member of all standing committees.
(B) President: In the absence or inability of the Chairman of the
---------
Board of Directors or during any vacancy in the office thereof, the President
shall preside at all meetings of the shareholders and the Board of Directors and
shall perform such other duties as may be assigned to him from time to time by
the Board of Directors, including, but not limited to, the signing or
countersigning of certificates of stock, bonds, notes, contracts or other
instruments of the Corporation as authorized by the Board of Directors. He
shall be ex-officio a member of all standing committees.
ARTICLE XIX
VICE PRESIDENTS
---------------
10
<PAGE>
Except as especially limited by resolution or vote of the Board of
Directors, any Vice President shall perform the duties and have the powers of
the President during the absence or disability of the President and shall have
power to sign all certificates of stock, deeds and contracts of this
Corporation. He shall perform such other duties and have such other powers as
the Board of Directors shall designate from time to time.
ARTICLE XX
SECRETARY
---------
The Secretary shall keep accurate minutes of all meetings of the Board
of Directors, the Executive Committee and the Stockholders, shall perform all
the duties commonly incident to this office, and shall perform such other duties
and have such other powers as the Board of Directors shall from time to time
designate. The Secretary shall have power, together with the Chairman of the
Board or the President or a Vice President, to sign certificates of stock of
this Corporation. In his absence, an Assistant Secretary or Secretary pro
tempore shall perform his duties.
ARTICLE XXI
TREASURER
---------
The Treasurer, subject to the order of the Board of Directors, shall
have the care and custody of the money, funds, valuable papers and documents of
this Corporation (other than his own bond which shall be in the custody of the
President) and shall have and exercise, under the supervision of the Board of
Directors, all the powers and duties commonly incident to his office, and shall
give bond in such form and with such sureties as may be required by the Board of
Directors.
11
<PAGE>
He shall deposit all funds of this Corporation in such bank or banks,
trust company or trust companies or with such firm or firms doing banking
business as the Directors shall designate or approve. He may endorse for
deposit or collection all checks, notes, et cetera, payable to this Corporation
or to its order, may accept drafts on behalf of this Corporation and, together
with the Chairman of the Board or the President or a Vice President, may sign
certificates of stock. He shall keep accurate books of account of this
Corporation's transactions which shall be the property of this Corporation and,
together with all its property of this Corporation, shall be subject at all
times to the inspection and control of the Board of Directors.
ARTICLE XXII
CONTROLLER
----------
The Controller, subject to the order of the Board of Directors, shall
be responsible for the accounting functions of the Corporation. He may be
assigned the additional responsibility of automated information systems. He
shall perform such other duties and have such other powers as the Board of
Directors shall designate from time to time.
12
<PAGE>
ARTICLE XXIII
RESIGNATIONS AND REMOVALS
-------------------------
Any Director or officer of this Corporation may resign at any time by
giving written notice to the Board of Directors or to the President or to the
Secretary of this Corporation, and any member of any committee may resign by
giving written notice either as aforesaid or to the committee of which he is a
member or to the chairman thereof. Any such resignation shall take effect at
the time specified therein or, if the time be not specified, upon receipt
thereof; and, unless otherwise specified therein, the acceptance of such
resignation shall not be necessary to make it effective.
The stockholders, at any meeting called for that purpose, by vote of
not less than two-thirds of the voting power of the stock issued and outstanding
and entitled to vote, may remove from office any director or officer elected or
appointed by the Stockholders. The Board of Directors, by vote of not less than
a majority of those present at a duly called meeting, may remove from office any
officer, agent or member or members of any committee elected or appointed by it
or by the Executive Committee.
The Compensation and Organization Committee, at any meeting called for
that purpose, or the Chief Executive Officer, or, in his absence, the President
of the Company, may immediately suspend from his or her office and the
performance of his or her duties any officer of the Company pending a regular
meeting of Directors or any meeting of the Board of Directors called for the
purposes of removing an officer of the Corporation.
13
<PAGE>
ARTICLE XXIV
VACANCIES
---------
If the office of any Director, officer or agent, one or more, becomes
vacant by reason of death, resignation, removal, disqualification or otherwise,
the Directors may, by vote of a majority of a quorum of the remaining Directors,
as constituted for the time being, choose a successor or successors who shall
hold office for the unexpired term. If there be less than a quorum of the
Directors at the time in office, said directors may, by a majority vote, choose
a successor or successors who shall hold office for the unexpired term.
Vacancies in the Board of Directors may be filled for an unexpired term by the
Stockholders at a meeting called for that purpose unless such vacancy shall have
been filled by the Directors.
ARTICLE XXV
MORTGAGING OF PROPERTY
----------------------
The Board of Directors, by vote of not less than a majority of the
board at a called meeting, may create any mortgage or other lien upon its
property and franchises to secure the issuance of bonds, notes and/or other
obligations of this Corporation without the consent of the Stockholders of his
Corporation.
ARTICLE XXVI
CAPITAL STOCK
-------------
The amount of capital stock shall be as fixed in the Articles of
Incorporation or in any lawful amendments thereto from time to time.
14
<PAGE>
ARTICLE XXVII
CERTIFICATES OF STOCK
---------------------
15
<PAGE>
Every stockholder shall be entitled to a certificate or certificates
of the capital stock of this Corporation in such form as may be prescribed by
the Board of Directors, duly numbered and sealed with the corporate seal of this
Corporation and setting forth the number of shares to which each stockholder is
entitled. Such certificates shall be signed by the Chairman of the Board or the
President, or a Vice President and by the Treasurer or an Assistant Treasurer or
the Secretary or an Assistant Secretary. The Board of Directors may also
appoint one or more Transfer Agents and/or Registrars for its capital stock of
any class or classes and may require stock certificates to be countersigned
and/or registered by one or more of such Transfer Agents and/or Registrars. If
certificates of capital stock of this Corporation are signed by a Transfer Agent
and by a Registrar, the signatures thereon of the Chairman of the Board or the
President or a Vice President and the Treasurer or an Assistant Treasurer or the
Secretary or an Assistant Secretary of this Corporation and the seal of this
Corporation thereon may be facsimiles, engraved or printed. Any provisions of
these By-Laws with reference to the signing and sealing of stock certificates
shall include, in cases above permitted, such facsimiles. In case any officer
or officers who shall have signed, or whose facsimile signature or signatures
shall have been used on, any such certificate or certificates shall cease to be
such officer or officers of this Corporation, whether because of death,
resignation or otherwise, before such certificate or certificates shall have
been delivered by this Corporation, such certificate or certificates may
nevertheless be adopted by the Board of Directors of this Corporation and be
issued and delivered as though the person or persons who signed such certificate
or certificates or whose facsimile signature or signatures shall have been used
thereon had not ceased to be such officer or officers of this Corporation.
16
<PAGE>
ARTICLE XXVIII
TRANSFER OF STOCK
-----------------
Shares of stock may be transferred by delivery of the certificate
accompanied either by an assignment in writing on the back of the certificate or
by a written power of attorney to sell, assign and transfer the same on the
books of this Corporation, signed by the person appearing by the certificate to
be the owner of the shares represented thereby, and shall be transferable on the
books of this Corporation upon surrender thereof so assigned or endorsed. The
person registered on the books of this Corporation as the owner of any shares of
stock shall exclusively be entitled as the owner of such shares, to receive
dividends and to vote as such owner in respect thereof. It shall be the duty of
every Stockholder to notify this Corporation of his post office address.
17
<PAGE>
ARTICLE XXIX
TRANSFER BOOKS
--------------
The transfer books of the stock of this Corporation may be closed
for such period from time to time, not exceeding forty (40) days, in
anticipation of Stockholders' meetings or the payment of dividends or the
allotment of rights as the Directors from time to time may determine, provided,
however, that in lieu of closing the transfer books as aforesaid, the Board of
Directors may fix in advance a date, not exceeding forty (40) days, as of which
Stockholders shall be entitled to vote at any meeting of the Stockholders or to
receive dividends or rights, and in such case such Stockholders and only such
Stockholders as shall be Stockholders of record as of the date so fixed shall be
entitled to vote at any such meeting and at any adjournment or adjournments
thereof or to receive dividends or rights, as the case may be, notwithstanding
any transfer of any stock on the books of this Corporation after such record
date fixed as aforesaid.
ARTICLE XXX
LOSS OF CERTIFICATES
--------------------
In case of the loss, mutilation or destruction of a certificate of
stock, a duplicate certificate may be issued upon such terms consistent with the
laws of the State of Nevada as the Directors shall prescribe.
18
<PAGE>
ARTICLE XXXI
SEAL
----
The seal of this Corporation shall consist of a flat-faced circular
die with the corporate name of this Corporation, the year of its incorporation
and the words "Corporate Seal Nevada" cut or engraved thereon. Said seal may be
used by causing it or a facsimile thereof to be impressed or affixed or
reproduced or otherwise.
ARTICLE XXXII
VOTING OF STOCK HELD
--------------------
Unless otherwise provided by resolution or vote of the Board of
Directors, the Chairman of the Board, the President or any Vice President, may
from time to time appoint an attorney or attorneys or agent or agents of this
Corporation, in the name on behalf of this Corporation to cast the votes which
this Corporation may be entitled to cast as a Stockholder or otherwise in any
other corporation, any of whose stock or securities may be held by this
Corporation, at meetings of the holders of the stock or other securities of such
other corporations, or to consent in writing to any action by any such other
corporation, and may instruct the person or persons so appointed as to the
manner of casting such votes or giving such consent and may execute or cause to
be executed on behalf of this Corporation and under its corporate seal, or
otherwise such written proxies, consents, waivers or other instruments as he may
deem necessary or proper in the premises; or the Chairman of the Board or the
President or any Vice President may himself attend any meeting of the holders of
stock or other securities of such other corporation and thereat vote or exercise
any or all other powers of this Corporation as the holder of such stock or other
securities of such other corporation.
19
<PAGE>
The Chairman of the Board or the President or any Vice President may
appoint one or more nominees in whose name or names stock or securities acquired
by this Corporation may be taken. With the approval of the Chairman of the
Board or the President or any Vice President of the Corporation (which approval
may be evidenced by his signature as witness on the instruments hereinafter
referred to) any such nominee may execute such written proxies, consents,
waivers or other instruments as he may be entitled to execute as the record
holder of stock or other securities owned by this Corporation.
ARTICLE XXXIII
EXECUTION OF CHECKS, DRAFTS, NOTES,
-----------------------------------
BONDS, DEBENTURES, ETC.
-----------------------
All checks, drafts, notes, bonds, debentures, or other obligations for
the payment of money shall be signed by such officer or officers, agent or
agents, as the Board of Directors shall by resolution or vote direct. The Board
of Directors may also, in its discretion, require, by resolution or vote, that
checks, drafts, notes, bonds, debentures, or other obligations for the payment
of money shall be countersigned or registered as a condition to their validity
by such officer or officers, agent or agents as shall be directed in such
resolution or vote. Checks for the total amount of any payroll and/or branch
office current expenses may be drawn in accordance with the foregoing provisions
and deposited in a special fund or funds. Checks upon such fund or funds may be
drawn by such person or persons as the Treasurer shall designate and need not be
countersigned.
20
<PAGE>
ARTICLE XXXIV
FACSIMILE SIGNATURES ON BONDS AND DEBENTURES
--------------------------------------------
The signatures of any officer or officers of this Corporation
executing a corporate bond or debenture or attesting the corporate seal thereon,
or upon any interest coupons annexed to any such corporate bond or debenture,
and the corporate seal affixed to any such bond or debenture, may be facsimiles,
engraves or printed, provided that such bond or debenture is authenticated or
certified with the manual signature of an authorized officer of the corporate
trustee designated by the indenture or other agreement under which said security
is issued or of an authorized officer of an authenticating agent appointed by
such corporate trustee. In case any officer or officers who signature or
signatures, whether manual or facsimile, shall have been used on any corporate
bond or debenture shall cease to be an officer or officers of the Corporation
for any reason before the same has been delivered by the Corporation, such bond
or debenture may nevertheless be issued and delivered as though the person or
persons who signatures were used thereon had not ceased to be such officer or
officers.
ARTICLE XXXV
SPECIAL PROVISIONS
------------------
Section 1:
- ---------
The private property of the stockholders, Directors or officers shall
not be subject to the payment of any corporate debts to any extent whatsoever.
21
<PAGE>
Section 2:
- ---------
(A) To the fullest extent that the laws of the State of Nevada, as in
effect on March 18, 1987, or as thereafter amended, permit elimination or
limitation of the liability of directors and officers, no Director, officer,
employee, fiduciary or authorized representative of the Company shall be
personally liable for monetary damages as such for any action taken, or any
failure to take any action, as a Director, officer or other representative
capacity.
(B) This Article shall not apply to any action filed prior to March
18, 1987, nor to any breach of performance or failure of performance of duty by
a Director, officer, employee, fiduciary or authorized representative occurring
prior to March, 1987. Any amendment or repeal of this Article which has the
effect of increasing Director liability shall operate prospectively only, and
shall not affect any action taken, or any failure to act, prior to its adoption.
Section 3:
- ---------
(A) Right to Indemnification. Except as prohibited by law, every
------------------------
Director and officer of the Company shall be entitled as a matter of right to be
indemnified by the Company against reasonable expense and any liability paid or
incurred by such person in connection with any actual or threatened claim,
action, suit or proceeding, civil, criminal, administrative, investigative or
other, whether brought by or in the right of the Company or otherwise, in which
he or she may be involved, as a party or otherwise, by reason of such person
being or having been a Director or officer of the Company or by reason of the
fact that such person is or was serving at the request of the Company as a
Director, officer,
22
<PAGE>
employee, fiduciary or other representative of the Corporation or another
corporation, partnership, joint venture, trust, employee benefit plan or other
entity (such claim, action, suit or proceeding hereafter being referred to as
"action"); provided, however, that no such right of indemnification shall exist
with respect to an action brought by a Director or officer against the Company
(other than a suit for indemnification as provided in paragraph (B)). Such
indemnification shall include the right to have expenses incurred by such person
in connection with an action paid in advance by the Company prior to final
disposition of such action, subject to such conditions as may be prescribed by
law. As used herein, "expense" shall include fees and expenses of counsel
selected by such person; and "liability" shall include amounts of judgments,
excise taxes, fines and penalties, and amounts paid in settlement.
(B) Right of Claimant to Bring Suit. If a claim under paragraph (A)
-------------------------------
of this Section is not paid in full by the Company within thirty (30) days after
a written claim has been received by the Company, the claimant may at any time
thereafter bring suit against the Company to recover the unpaid amount of the
claim, and, if successful in whole or in part, the claimant shall also be
entitled to be paid the expense of prosecuting such claim. It shall be a
defense to any such action that the conduct of the claimant was such that under
Nevada law the Company would be prohibited from indemnifying the claimant for
the amount claimed, but the burden of proving such defense shall be on the
Company. Neither the failure of the Company (including its Board of Directors,
independent legal counsel and its stockholders) to have made a determination
prior to the commencement of such action that indemnification of the claimant is
proper in the circumstances because the conduct of the claimant was not such
that indemnification would be prohibited by law, nor an actual
23
<PAGE>
determination by the Company (including the Board of Directors, independent
legal counsel or its stockholders) that the conduct of the claimant was such
that indemnification would be prohibited by law, shall be a defense to the
action or create a presumption that the conduct of the claimant was such that
indemnification would be prohibited by law.
(C) Insurance and Funding. The Company may purchase and maintain
---------------------
insurance to protect itself and any person eligible to be indemnified hereunder
against any liability or expense asserted or incurred by such person in
connection with any action, whether or not the Company would have the power to
indemnify such person against such liability or expense by law or under the
provisions of this Section 3. The Company may make other financial arrangements
which include a trust fund, program of self-insurance, grant a security interest
or other lien on any assets of the corporation, establish a letter of credit,
guaranty or surety as set forth in 1987 Statutes of Nevada, Chapter 28 to ensure
the payment of such sums as may become necessary to effect indemnification as
provided herein.
(D) Non-Exclusive; Nature and Extent of Rights. The right of
------------------------------------------
indemnification provided for herein (1) shall not be deemed exclusive of any
other rights, whether now existing or hereafter created, to which those seeking
indemnification hereunder may be entitled under any agreement, by-law or article
provision, vote of stockholders or directors or otherwise, (2) shall be deemed
to create contractual rights in favor of persons entitled to indemnification
hereunder, (3) shall continue as to persons who have ceased to have the status
pursuant to which they were entitled or were denominated as entitled to
indemnification hereunder and shall inure to the benefit of the heirs and legal
representatives of persons entitled to indemnification hereunder, and (4) shall
be applicable
24
<PAGE>
to actions, suits or proceedings commenced after the adoption hereof, whether
arising from acts or omissions occurring before or after the adoption hereof.
The right of indemnification provided for herein may not be amended, modified or
repealed so as to limit in any way the indemnification provided for herein with
respect to any acts or omissions occurring prior to the adoption of any such
amendment or repeal.
Section 4:
- ---------
In furtherance, and not in limitation, of the powers conferred by
statute, the Board of Directors, by a majority vote of those present at any
called meeting, is expressly authorized:
(A) To hold its meetings, to have one or more offices and to keep the
books of the Corporation, except as may be otherwise specifically required by
the laws of the State of Nevada, within or without the State of Nevada, at such
places as may be from time to time designated by it.
(B) To determine from time to time whether, and if allowed under what
conditions and regulations, the accounts and books of the Corporation (other
than the books required by law to be kept at the principal office of the
Corporation in Nevada), or any of them, shall be open to inspection of the
stockholders, and the stockholders' rights in this respect are and shall be
restricted or limited accordingly.
(C) To make, alter, amend and rescind the By-Laws of the Corporation,
to fix the amount to be reserved as working capital, to fix the times for the
declaration and payment of dividends, and to authorize and cause to be executed
mortgages and liens upon the real and personal property of the Corporation.
25
<PAGE>
(D) To designate from its number an executive committee, which, to the
extent provided by the By-Laws of the Corporation or by resolution of the Board
of Directors, shall have and may exercise in the intervals between meetings of
the Board of Directors, the powers thereof which may lawfully be delegated in
respect of the management of the business and the affairs of the Corporation,
and shall have power to authorize the seal of the Corporation to be affixed to
such papers as may require it. The Board of Directors may also, in its
discretion, designate from its number a finance committee and delegate thereto
such of the powers of the Board of Directors as may be lawfully delegated, to be
exercised when the Board is not in session.
ARTICLE XXXVI
AMENDMENTS
----------
These By-Laws may be amended, added to, altered or repealed in whole
or in part at any Annual or Special Meeting of the Stockholders by vote in
either case of a majority of the voting power of the capital stock issued and
outstanding and entitled to vote, provided notice of the general nature or
character of the proposed amendment, addition, alteration or repeal is given in
the notice of said meeting, or by the affirmative vote of a majority of the
Board of Directors present at a called Regular or Special Meeting of the Board
of Directors, provided notice of the general nature or character of the proposed
amendment, addition, alteration or repeal is given in the notice of said
meeting.
26
<PAGE>
(12)(A)
SIERRA PACIFIC POWER COMPANY
CALCULATION OF PRE-TAX INTEREST COVERAGES
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Total Income Before
Interest Charges $113,106 $ 99,678 $100,388
Add: Income Taxes:
Included in operating expense 36,241 37,801 29,114
Included in other income-net (1,238) (662) 750
Allowance For Borrowed Funds
-------- -------- --------
Used During Construction 3,924 3,412 1,502
-------- -------- --------
Total Numerator $152,033 $140,229 $131,754
======== ======== ========
Interest Charges:
Long-Term Debt $ 38,855 $ 35,326 $ 35,193
Other 4,579 1,781 5,834
-------- -------- --------
Total Denominator $ 43,434 $ 37,107 $ 41,027
======== ======== ========
Pre-Tax Interest Coverage 3.50 3.78 3.21
======== ======== ========
</TABLE>
<PAGE>
(23)(A)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No. 333-
17041 of Sierra Pacific Power Company on Form S-3 of our report dated February
14, 1997, appearing in and incorporated by reference in the Annual Report on
Form 10-K of Sierra Pacific Power Company for the year ended December 31, 1996.
DELOITTE & TOUCHE, LLP
Reno, Nevada
March 21, 1997
<PAGE>
(23)(B)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos. 33-
90284 and 333-4374 of Sierra Pacific Resources on Forms S-3 and Registration
Statement Nos. 2-92454, 33-87646, and 33-48152 of Sierra Pacific Resources on
Forms S-8 of our report dated February 16, 1996, appearing in and incorporated
by reference in the Annual Report on Form 10-K of Sierra Pacific Resources for
the year ended December 31, 1996.
We also consent to the incorporation by reference in Registration Statement No.
2-92454 of Sierra Pacific Resources on Form S-8 of our report dated February 29,
1996, appearing in the Annual Report on Form 11-K of Sierra Pacific Resources
Employees' Stock Ownership Plan for the year ended December 31, 1996.
COOPERS & LYBRAND L.L.P.
San Francisco, California
March 21, 1997
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
COMPANY'S FINANCIAL RECORDS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,543,210
<OTHER-PROPERTY-AND-INVEST> 22,394
<TOTAL-CURRENT-ASSETS> 127,206
<TOTAL-DEFERRED-CHARGES> 149,818
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,842,628
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 0
<TOTAL-COMMON-STOCKHOLDERS-EQ> 606,896
48,500
73,115
<LONG-TERM-DEBT-NET> 607,287
<SHORT-TERM-NOTES> 38,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 15,434
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 453,396
<TOT-CAPITALIZATION-AND-LIAB> 1,842,628
<GROSS-OPERATING-REVENUE> 619,724
<INCOME-TAX-EXPENSE> 36,241
<OTHER-OPERATING-EXPENSES> 476,475
<TOTAL-OPERATING-EXPENSES> 512,716
<OPERATING-INCOME-LOSS> 107,008
<OTHER-INCOME-NET> 6,098
<INCOME-BEFORE-INTEREST-EXPEN> 113,106
<TOTAL-INTEREST-EXPENSE> 37,706
<NET-INCOME> 75,400
8,049
<EARNINGS-AVAILABLE-FOR-COMM> 67,351
<COMMON-STOCK-DIVIDENDS> 61,510
<TOTAL-INTEREST-ON-BONDS> 37,466
<CASH-FLOW-OPERATIONS> 110,666
<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 EPS information.
</FN>
</TABLE>
