1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED] FOR THE FISCAL YEAR ENDED DECEMBER
31, 1995 OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED] FOR THE TRANSITION PERIOD FROM
TO
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COMMISSION FILE NUMBER 1-3701
THE WASHINGTON WATER POWER COMPANY
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(Exact name of Registrant as specified in its charter)
Washington 91-0462470
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1411 East Mission Avenue, Spokane, Washington 99202-2600
- ---------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 509-489-0500
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of Each Exchange
Title of Class on Which Registered
- --------------------------------------------------- -----------------------
Common Stock, no par value, together with New York Stock Exchange
Preferred Share Purchase Rights appurtenant thereto Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Title of Class
--------------
Preferred Stock, Cumulative, Without Par Value
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 (Section 229.405 of this chapter) 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]
The aggregate market value of the Registrant's outstanding Common Stock, no par
value (the only class of voting stock), held by non-affiliates is
$1,035,266,660.00, based on the last reported sale price thereof on the
consolidated tape on February 29, 1996.
At February 29, 1996, 55,960,360 shares of Registrant's Common Stock, no par
value (the only class of common stock), were outstanding.
Documents Incorporated By Reference
Part of Form 10-K into Which
Document Document is Incorporated
- --------------------------------------- ----------------------------
Proxy Statement to be filed in Part III, Items 10, 11,
connection with the annual meeting 12 and 13
of shareholders to be held May 13, 1996
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INDEX
Item Page
No. No.
- ---- ----
Acronyms and Terms......................................... iii
Part I
1. Business................................................... 1
Company Overview......................................... 1
Merger Agreement Overview................................ 1
Utility Operations Overview.............................. 1
Non-Utility Overview..................................... 2
Electric Service......................................... 3
General Business Conditions.............................. 3
Electric Load Requirements............................... 4
Electric Resources....................................... 4
Electric Regulatory Issues............................... 5
Electric Operating Statistics............................ 7
Natural Gas Service...................................... 8
General Business Conditions.............................. 8
Natural Gas Resources.................................... 8
Natural Gas Regulatory Issues............................ 9
Natural Gas Operating Statistics......................... 10
Environmental Issues..................................... 11
Non-Utility Business..................................... 12
2. Properties................................................. 13
Electric Properties...................................... 13
Natural Gas Properties................................... 14
3. Legal Proceedings.......................................... 14
4. Submission of Matters to a Vote of Security Holders........ 14
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 15
6. Selected Financial Data.................................... 16
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 17
Results of Operations.................................... 17
Liquidity and Capital Resources.......................... 20
Future Outlook........................................... 21
8. Financial Statements and Supplementary Data................ 25
Independent Auditors' Report............................. 26
Financial Statements..................................... 27
Notes to Financial Statements............................ 32
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure....................... *
Part III
10. Directors and Executive Officers of the Registrant......... 50
11. Executive Compensation..................................... 51
12. Security Ownership of Certain Beneficial Owners
and Management............................................ 51
13. Certain Relationships and Related Transactions............. 51
Part IV
14. Financial Statements, Financial Statement Schedules,
Exhibits and Reports on Form 8-K.......................... 52
Signatures................................................. 53
Independent Auditors' Consent.............................. 54
Exhibit Index.............................................. 55
* = not an applicable item in the 1995 calendar year for the Company
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ACRONYMS AND TERMS
(The following acronyms and terms are found in
multiple locations within the document)
Acronym/Term Meaning
- ------------ -------
aMW - Average Megawatt - a measure of electrical energy over time
BPA - Bonneville Power Administration
Capacity - a measure of the rate at which a particular generating source produces electricity
Centralia - the coal fired Centralia Power Plant in western Washington State
Colstrip - the coal fired Colstrip Generating Project in southeastern Montana
CPUC - California Public Utilities Commission
CT - combustion turbine; a natural gas fired unit used primarily for peaking needs
DSM - Demand Side Management - the process of helping customers manage
their use of energy resources
Energy - a measure of the amount of electricity produced from a particular generating
source over time
FERC - Federal Energy Regulatory Commission
IPUC - Idaho Public Utilities Commission
IRP - Integrated Resource Planning
KW, KWH - Kilowatt, kilowatthour, 1000 watts or 1000 watt hours
MW, MWH - Megawatt, megawatthour, 1000 KW or 1000 KWH
MPSC - Montana Public Service Commission
OPUC - Public Utility Commission of Oregon
Pentzer - Pentzer Corporation, a wholly-owned subsidiary of the Company which is the
parent company to the majority of the Company's non-utility businesses
Therm - Unit of measurement for natural gas; a therm is equal to one hundred cubic feet
(volume) or 100,000 BTUs (energy)
Watt - Unit of measurement for electricity; a watt is equal to the rate of work represented
by a current of one ampere under a pressure of one volt
WIDCo - Washington Irrigation & Development Company, a wholly-owned non-utility
subsidiary of the Company
WUTC - Washington Utilities and Transportation Commission
WWP - The Washington Water Power Company, the Company
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PART I
Item 1. Business
Company Overview
The Washington Water Power Company (Company), which was incorporated in the
State of Washington in 1889, primarily operates in the electric and natural gas
utility businesses. As of December 31, 1995, the Company provides electricity
and natural gas in a 26,000 square mile area in eastern Washington and northern
Idaho with a population of approximately 765,000. The Company also provides
natural gas service in a 4,000 square mile area in northeast and southwest
Oregon and in the South Lake Tahoe region of California with a population of
approximately 460,000.
The Company's retail and wholesale utility businesses include the generation,
purchase, transmission, distribution and sale of electric energy plus the
purchase, transportation, distribution and sale of natural gas. In addition to
its utility businesses, the Company owns Pentzer Corporation (Pentzer), parent
company to the majority of the Company's non-utility businesses.
At December 31, 1995, the Company's employees included 1,390 people in its
utility operations and 1,240 people in its majority-owned non-utility
businesses. The Company's corporate headquarters are in Spokane, Washington
(Spokane), which serves as the Inland Northwest's center for manufacturing,
transportation, health care, education, communication, agricultural and service
businesses.
For the twelve months ended December 31, 1995, 1994 and 1993, respectively, the
Company derived operating revenues and income from operations in the following
proportions:
Operating Revenues Income from Operations
------------------ ----------------------
1995 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ----
Electricity 65% 67% 73% 80% 81% 80%
Natural Gas 23% 24% 21% 13% 15% 15%
Non-Utility 12% 9% 6% 7% 4% 5%
Merger Agreement Overview
In June, 1994, the Company entered into a merger agreement with Sierra Pacific
Resources (SPR), Sierra Pacific Power Company (SPPC) and Altus Corporation
(Altus, formerly named Resources West Energy Corporation). In 1994,
applications seeking approval of the merger were filed with the Federal Energy
Regulatory Commission (FERC) and with the state utility commissions of
California, Idaho, Montana, Nevada, Oregon and Washington. The Montana Public
Service Commission issued an order in October 1994 declining to exercise
jurisdiction. The Company has received orders approving the merger from the
commissions of all the other states.
On November 29, 1995, the FERC ordered evidentiary hearings concerning the
proposed merger. Issues raised by the FERC primarily revolve around
single-system versus zonal transmission rates, pricing for inter-divisional
energy transfers, justification of cost savings and the effects on competition,
including access by third-party users to the merged company's transmission
system, the resolution of which could have an impact on the level of anticipated
savings. An administrative law judge has been assigned to the merger proceeding
and a pre-hearing conference was held on December 13, 1995 to set a procedural
schedule. The companies filed supplemental testimony on February 1, 1996.
Hearings are scheduled to begin on June 4, 1996. Based on this schedule, the
companies believe an order could be issued by the FERC in 1996 or early 1997.
Most of the final orders issued by state commissions include a "reopener" clause
that allows the state proceedings to be reopened if any party believes that the
FERC or any other state commission has taken some action which makes the
Stipulation in such state undesirable.
See Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations: Future Outlook and Note 16 to Financial Statements for
additional information.
Utility Operations Overview
The Company owns and operates nine hydroelectric projects, a wood-waste fueled
generating station and three natural gas combustion turbine (CT) peaking units.
The Company also owns a 15% share in two coal-fired generating facilities. The
Company contracts with five natural gas pipeline companies for access to
domestic and Canadian natural gas supplies.
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With this diverse energy resource portfolio, the Company remains one of the
nation's lowest-cost producers and sellers of energy services.
At the end of 1995, retail electric service was supplied to approximately
290,000 customers in eastern Washington and northern Idaho. The Company's
average hourly load for 1995 was 924 aMW. The Company's annual peak load,
including firm contractual obligations, was 2,545 MW. This peak occurred on
December 8, 1995, at which time the maximum capacity available from the
Company's generating facilities, in addition to firm and non-firm purchases, was
2,855 MW.
At the end of 1995, the Company's natural gas operations served approximately
224,000 customers in parts of Washington, Idaho, Oregon and California. The
peak load in 1995 occurred on February 13, 1995 when 2.8 million therms were
required. During that peak, 3.5 million therms were available under firm
transportation and storage contracts.
In early 1996, the Company experienced record peak loads. The electric peak
occurred on February 1, 1996, when the load, including firm and non-firm
contractual obligations, totaled 2,936 MW, at which time the maximum capacity
available from the Company's generating facilities, in addition to firm and
non-firm purchases, was 3,216 MW. The natural gas peak load occurred on
January 31, 1996 when approximately 3.5 million therms were required. During
that peak, 3.5 million therms were available under firm transportation and
storage contracts.
Non-Utility Overview
The Company's principal subsidiary is Pentzer, a wholly owned private investment
company whose current portfolio of investments includes companies involved in
consumer product promotion, specialty tool manufacturing, metal fabrication,
financial services, electronic technology and industrial real estate
development.
As of December 31, 1995, Pentzer had approximately $220 million in total assets,
or about 10% of the Company's consolidated assets, and about $123 million in
shareholder equity.
See Item 1. Business - Non-Utility Business and Note 15 to Financial Statements
for additional information.
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ELECTRIC SERVICE
GENERAL BUSINESS CONDITIONS
Regulatory, economic and technological changes have brought about the
accelerating transformation of the electric utility industry from a vertically
integrated monopoly to a business all segments of which are more market driven.
The Company believes that it is well positioned to meet the challenges of
increased competition due to its low production costs, close proximity to major
transmission lines, active participation in wholesale power markets and its
dedication to exceptional customer service and business improvement.
Challenges facing the retail electric business include evolving technologies
which provide alternate energy supplies, reduced energy consumption and the cost
of the energy supplied, self-generation and fuel switching by commercial and
industrial customers, as well as the potential for retail wheeling, the costs of
increasingly stringent environmental laws and the potential for stranded or
nonrecoverable utility assets. The Company continues to compete in the
wholesale electric market with other western utilities, federal marketing
agencies and power marketers. Business challenges affecting the wholesale
electric business include new entrants in the wholesale market, such as power
brokers and marketers, competition from low-cost generation being developed by
independent power producers and declining margins.
The National Energy Policy Act (NEPA) enacted in 1992 addresses a wide range of
issues affecting the wholesale electric business. NEPA gives the FERC expanded
authority to order electric utilities to transmit electric power for wholesale
purchasers and sellers and increase transmission capacity to provide access at
prices that permit the recovery of all costs incurred in connection with the
transmission services. NEPA also created a new exception from the provisions of
the Public Utility Holding Company Act of 1935 for Exempt Wholesale Generators
(EWG). Subject to satisfying various regulatory requirements, EWGs may own
generating facilities and make wholesale sales.
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking (NOPR)
relating to transmission services and a supplemental NOPR on Recovery of
Stranded Costs. If adopted, the NOPR on open access transmission would require
public utilities operating under the Federal Power Act to provide third-party
access to their transmission systems. Each utility would also be required to
establish separate rates for its transmission and generation services for new
wholesale service. Further, utilities would be required to take transmission
service under the same tariffs applicable to third-party users. The FERC
requested comments on the desirability of unified standards for both wholesale
and retail transmission services. The FERC suggested, as a possible approach,
the establishment by each vertically integrated electric utility of a
distribution function which would be treated as a wholesale customer taking
transmission services under the utility's filed wholesale transmission tariff.
The FERC recognized, and numerous comments confirmed, that such an approach
would change the traditional approach of state-federal allocation of
transmission costs. The supplemental NOPR on stranded costs provides a basis for
recovery by regulated public utilities of legitimate and verifiable stranded
costs associated with existing wholesale requirements customers and retail
customers who become unbundled wholesale transmission customers of the utility.
The FERC will consider allowing recovery of stranded investment costs associated
with retail wheeling only if a state regulatory commission lacks the authority
to consider that issue. It is anticipated that the final rules could take
effect in the first half of 1996.
The Company does not believe that the Open Access NOPR will have a material
effect on the Company's results of operations, assuming that the final rule is
adopted substantially as proposed. However, if, in the pending or a subsequent
rule-making proceeding, the FERC adopted a rule which had the effect of
requiring the wholesale transmission rate to be recognized as the transmission
component of retail rates, and if the FERC imposed single-system transmission
rates on Altus in the Merger proceeding, this could lead to a reduction of
Altus' retail rates in Nevada but would not necessarily result in a
corresponding increase in Washington and Idaho. See Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations:
Future Outlook.
Open access tariffs were submitted to the FERC for Altus as a part of the
Company/SPR merger application. The Company filed separate open
access tariffs on February 29, 1996 in order to provide for open transmission
access prior to the merger.
On January 31, 1996, the FERC issued a Notice of Inquiry Concerning Commission's
Merger Policy (Merger NOI). The Merger NOI will give the FERC the benefit of
public input on how proposed mergers should be evaluated in an open access
environment. Comments on the Merger NOI are due by the end of March 1996.
The Washington Utilities and Transportation Commission (WUTC) has issued guiding
principles related to its December 1994 Notice of Inquiry (NOI) entitled
"Examining Regulation of Electric Utilities in the Face of Change in the
Electric Industry." In January 1996, the Idaho Public Utilities Commission
(IPUC) initiated a similar NOI and will hold technical workshops later in 1996.
(See Electric Regulatory Issues below.)
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If electric utility companies are eventually required to provide retail wheeling
service, which is the transmission of electric power from another supplier to a
customer located within such utility's service area, the Company believes it
will be in a position to benefit since it is committed to remaining one of the
country's lowest-cost providers of electric energy. Consequently, the Company
believes it faces minimal risk for stranded generation, transmission or
distribution assets due to its low cost structure.
ELECTRIC LOAD REQUIREMENTS
The Company provides electric services to retail and wholesale customers. Retail
service is provided to 290,000 electric customers. Firm sales to residential,
commercial and industrial customers constituted 97% of the retail sales in 1995.
Sales to the retail customers are affected by temperature variations, economic
conditions and growth in the number of customers. The 1995 annual peak for the
retail customer group was 2,545 MW. On February 1, 1996, a new peak of 2,936 MW
was recorded due to record cold weather.
The Company's wholesale electric business remains an important part of the
Company's overall business strategy. Since 1987, the Company has entered into a
number of long-term firm power sales contracts that have increased its wholesale
electric business and the Company is continuing to actively pursue electric
wholesale business opportunities. In 1995, the Company entered into five new
firm wholesale contracts which brought the total non-coincident peak
requirements to 972 MW of capacity. Wholesale sales are affected by weather and
streamflow conditions and may be affected over time by the restructuring of the
electric utility industry.
ELECTRIC RESOURCES
The Company's diverse resource mix of hydroelectric projects, thermal generating
facilities and power purchases and exchanges, combined with strategic access to
regional electric transmission systems, enables the Company to remain one of the
nation's lowest-cost producers and sellers of electric energy services.
Hydroelectric Resources Hydroelectric generation is the Company's lowest cost
source of electricity and the availability of hydroelectric generation has a
significant effect on the Company's total energy costs. The Company expects to
meet about 49% of its total energy requirements with its own hydroelectric
generation and long-term hydroelectric contracts in normal water years. The
streamflows to Company-owned hydroelectric projects were 120%, 65% and 86% of
normal in 1995, 1994 and 1993, respectively. For the years 1995, 1994 and 1993,
respectively, 43%, 38% and 43% of the Company's total energy requirements were
met by these hydroelectric resources.
Thermal Resources The Company has a 15% interest in each of two twin-unit
coal-fired facilities - the Centralia Power Plant in western Washington and
Units 3 and 4 of the Colstrip Generating Project in southeastern Montana. In
addition, the Company owns a wood-waste-fired facility known as the Kettle Falls
Generating Station in northeastern Washington and three natural gas-fired CTs,
one located in Spokane and two in northern Idaho, used for peaking needs.
Company-owned thermal facilities provided 21%, 32% and 25% of the Company's
total energy requirements for the years 1995, 1994 and 1993, respectively.
Centralia, which is operated by PacifiCorp, is supplied with coal under both a
fuel supply agreement in effect through December 2020 and various spot market
purchases. In 1995, 1994 and 1993, Centralia provided approximately 30%, 42%
and 46%, respectively, of the Company's thermal generation.
Colstrip is supplied with fuel under coal supply and transportation agreements
in effect through December 2019 from adjacent coal reserves. The Montana Power
Company is the operator of Colstrip. In 1995, 1994 and 1993 Colstrip provided
approximately 47%, 48%, and 43% of the Company's thermal generation,
respectively.
Kettle Falls' primary fuel is wood-waste generated as a by-product from forest
industry operations within one hundred miles of the plant. Natural gas may be
used as an alternate fuel. A combination of long-term contracts plus spot
purchases provides the Company the flexibility to meet expected future fuel
requirements for the plant. In 1995, 1994 and 1993, Kettle Falls provided
approximately 8%, 10% and 11% of the Company's thermal generation, respectively.
The CTs are natural gas-fired units, primarily used for peaking needs. The two
units in northern Idaho were completed and went into service in early January
1995. The CTs have access to domestic and Canadian natural gas supplied through
Pacific Gas Transmission (PGT). In 1995, these units provided approximately 15%
of the Company's thermal generation primarily due to the low cost of natural gas
during the year. Thermal generation provided by the Spokane CT in prior years
was immaterial.
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Purchases, Exchanges and Sales In 1995, the Company had various purchase
contracts equating to a non-coincident peak of 418 MW, with an average remaining
life of 6.7 years. Additionally, long-term hydro purchase contracts of 255 MW
were available with an average remaining contract life of 10.5 years. The
Company also enters into a significant amount of short-term sales and purchases
with durations of up to one-year from surplus Company resources and short-term
contracts. Other energy purchases and exchanges for the years 1995, 1994 and
1993 provided approximately 36%, 30% and 32%, respectively, of the Company's
total electric energy requirements, including wholesale obligations.
Under the Public Utility Regulatory Policies Act of 1978 (PURPA), the Company is
required to purchase generation from qualifying facilities, including small
hydroelectric and cogeneration projects, at avoided cost rates adopted by the
WUTC and the IPUC. The Company purchased approximately 632,000 MW, or about
5% of the Company's total energy requirements, from these sources at a cost of
approximately $27 million in 1995. Current avoided costs range from 2.5 cents
per KWH in 1996 to 5.4 cents in 2005 in Washington for projects under one MW.
In Idaho, the interim avoided cost rates range from 2.1 cents in 1996 to 4.5
cents in 2005 for projects under one MW. For larger projects, the rates are
negotiated and reflect current market conditions.
ELECTRIC REGULATORY ISSUES
The Company, as a public utility, is currently subject to regulation by state
utility commissions with respect to rates, accounting, the issuance of
securities and other matters. The electric retail operations are subject to the
jurisdiction of the WUTC and IPUC. The Company is also subject to the
jurisdiction of the FERC for its accounting procedures and its wholesale
transmission rates.
In each regulatory jurisdiction, the price the Company may charge for utility
services (other than certain wholesale sales and specially negotiated retail
rates for industrial or large commercial customers) is currently determined on a
"cost of service" basis and is designed to provide, after recovery of allowable
operating expenses, an opportunity to earn a reasonable return on "rate base."
"Rate base" is generally determined by reference to the original cost (net of
accumulated depreciation) of utility plant in service, subject to various
adjustments for deferred taxes and other items. Over time, rate base is
increased by additions to utility plant in service and reduced by depreciation
and retirements of utility plant from service.
The Company is a licensee under the Federal Power Act and its licensed projects
are subject to the provisions of Part I of that Act. These provisions include
payment for headwater benefits, condemnation of licensed projects upon payment
of just compensation and take-over of such projects after the expiration of the
license upon payment of the lesser of "net investment" or "fair value" of the
project, in either case plus severance damages. See Item 2. Properties -
Electric Properties for additional information.
General Rate Cases The Company does not currently plan to file for any general
electric rate increases in 1996. See Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations: Future Outlook for
additional information regarding rate freezes related to the proposed merger
between the Company, SPPC and SPR. The Company's most recent general electric
rate case in Washington was effective in March 1987 and allowed a return on
equity of 12.90%. The effective change was a $15.5 million, or 8.9%, increase
in anticipated annual revenues. The Company's most recent general electric rate
case in Idaho was effective in September 1986 and allowed a return on equity of
12.90%. The effective change was an increase of $3.7 million, or 4.3%, in
anticipated annual revenues. The Company anticipates that future rate filings
will move away from rate of return regulation toward a performance-based
regulatory system.
Integrated Resource Planning (IRP) IRP is a process required by both the WUTC
and IPUC and represents the Company's responsibility to meet customer demand for
reliable electric energy services at the lowest total cost to both the Company
and its customers. The process entails (1) the forecasting of future electric
energy needs, (2) the assessment of energy supplies, conservation options,
customer costs, and social and environmental impacts and (3) the development of
action plans which support a least cost resource strategy. Both the WUTC and
IPUC acknowledge the plans as part of a public hearing process but do not
approve the resource plans due to concerns about pre-approval outside of actual
rate cases. The state commissions place an emphasis on the IRP as an
informational tool for long-term planning. The Company is required to file an
updated IRP every two years, and filed with both the WUTC and IPUC in April
1995.
Notice of Inquiry (NOI) In December 1994, the WUTC initiated an NOI entitled,
"Examining Regulation of Electric Utilities in the Face of Change in the
Electric Industry." The WUTC sought comments on the potential structural change
in the electric industry, the implications of industry changes for utility
regulation and recommendations concerning specific rules and regulations
currently used by the WUTC. The NOI process concluded in December 1995 with the
issuance by the WUTC of eight guiding principles stating basically that future
WUTC regulatory oversight will balance issues such as reliability, pricing
responsive to customer needs and selected public policy concerns. In January
1996, the IPUC initiated a similar NOI entitled, "Investigation into Changes
Occurring in the Electric Industry." The NOI outlines seven issues which
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the IPUC believes will need regulatory oversight into the future. After two
technical workshops, the IPUC intends to issue a proposed order adopting these
issues as guiding principles later in 1996.
Demand Side Management (DSM) The WUTC and IPUC approved as filed, effective
January 1, 1995, the Company's proposed electric and natural gas DSM programs
for a two-year period ending December 31, 1996. The Company's DSM programs
focus on both the continuation of selected existing programs available to broad
customer classes and the development of specifically structured programs to
influence market demand. The Company's programs, while maintaining a
residential electric weatherization program and fuel efficiency awareness
programs, now place a greater emphasis on commercial and industrial programs.
In a two-year experimental program, the WUTC approved the Company's requested
DSM Tariff Rider as filed, effective January 1, 1995. The tariff rider is a
separate revenue source and represents a 1.55% electric revenue increase and a
0.52% natural gas increase. The revenues will be used to fund the Company's
1995 and 1996 DSM program expenditures. Under previous accounting treatment,
DSM investments, including the applicable interest charge known as Allowance for
Funds Used to Conserve Energy (AFUCE), were recorded as deferred assets until an
application was made in a future general rate case. The new treatment will
treat 1995 and 1996 DSM expenditures as operating expenses during the two-year
experimental period. The IPUC approved a similar proposal effective March 10,
1995.
Power Cost Adjustment (PCA) In 1989, the IPUC approved the Company's filing for
a PCA whereby the Company is allowed to modify electric rates to recover or
rebate a portion of the difference between actual and allowed net power supply
costs. In July of 1994, the IPUC approved an indefinite extension of the
Company's proposed modifications to the PCA. The modified PCA tracks changes in
hydroelectric generation, secondary prices, related changes in thermal
generation and PURPA contracts, but it no longer tracks changes in revenues or
costs associated with other wheeling or power contracts. Rate changes are
triggered when the deferred balance reaches $2.2 million. On January 1, 1995, a
$2.2 million, or 2.5%, surcharge was implemented which expired on December 31,
1995. On September 1, 1995, a $2.3 million, or 2.4%, surcharge was implemented
which will expire on August 31, 1996. See Note 1 to Financial Statements for
additional details.
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ELECTRIC OPERATING STATISTICS
Years Ended December 31,
1995 1994 1993
ENERGY RESOURCES (thousand MWh):
Hydro generation (from Company facilities)........ 4,038 2,904 3,548
Thermal generation (from Company facilities)...... 2,537 3,427 2,791
Purchased power - long-term hydro................. 1,159 1,177 1,117
Purchased power - other........................... 4,113 3,146 3,492
Power exchanges................................... 156 (24) 81
-------- -------- --------
Total power resources........................... 12,003 10,630 11,029
Energy losses and Company use..................... (525) (504) (598)
-------- -------- --------
Total energy resources (net of losses).......... 11,478 10,126 10,431
======== ======== ========
ENERGY REQUIREMENTS (thousand MWh):
Residential....................................... 3,150 3,035 3,134
Commercial........................................ 2,592 2,477 2,373
Industrial........................................ 1,803 1,705 1,644
Public street and highway lighting................ 23 22 22
-------- -------- --------
Total retail requirements....................... 7,568 7,239 7,173
Firm wholesale.................................... 1,953 1,523 1,798
Non-firm wholesale................................ 1,957 1,364 1,460
-------- -------- --------
Total energy requirements....................... 11,478 10,126 10,431
======== ======== =======
RESOURCE AVAILABILITY at time of system peak (MW):
Total requirements (winter) (1)................... 2,545 2,233 2,126
Total resource availability (winter).............. 2,855 2,468 2,335
Total requirements (summer) (2)................... 2,037 1,793 1,682
Total resource availability (summer).............. 2,660 2,392 2,206
ELECTRIC OPERATING REVENUES (Thousands of Dollars):
Residential....................................... $156,755 $146,894 $153,929
Commercial........................................ 140,221 131,254 126,256
Industrial........................................ 60,979 57,438 57,133
Public street and highway lighting................ 3,345 3,108 3,022
-------- -------- --------
Total retail revenue............................ 361,300 338,694 340,340
Firm wholesale.................................... 84,220 64,890 65,420
Non-firm wholesale................................ 25,013 26,496 43,214
-------- -------- --------
Total energy revenues........................... 470,533 430,080 448,974
Other revenues.................................... 16,456 21,211 15,201
-------- -------- --------
Total electric revenues.............................. $486,989 $451,291 $464,175
======== ======== ========
Income from electric operations - After income tax... $110,075 $92,918 $92,850
======== ======== ========
NUMBER OF ELECTRIC CUSTOMERS (Average for Period):
Residential....................................... 253,364 239,733 233,795
Commercial........................................ 32,236 29,402 28,678
Industrial........................................ 1,107 999 963
Public street and highway lighting................ 349 325 308
-------- -------- --------
Total retail customers.......................... 287,056 270,459 263,744
Wholesale customers............................... 33 27 28
-------- -------- --------
Total electric customers........................ 287,089 270,486 263,772
======== ======== ========
ELECTRIC RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (KWh)...................... 12,434 12,661 13,406
Revenue per KWh (in cents)......................... 4.98 4.84 4.91
Annual revenue per customer........................ $618.69 $612.74 $658.39
(1) Includes firm contract obligations of 733 MW, 539 MW and 485 MW and 327 MW,
242 MW and 120 MW of non-firm sales in 1995, 1994 and 1993, respectively.
(2) Includes firm contract obligations of 691 MW, 509 MW and 610 MW in 1995,
1994 and 1993, respectively, and non-firm sales of 125 MW and 1 MW in 1995
and 1994, respectively. There were no non-firm sales in 1993 during the
summer system peak period.
7
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THE WASHINGTON WATER POWER COMPANY
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NATURAL GAS SERVICE
GENERAL BUSINESS CONDITIONS
Natural gas remains competitively priced compared to alternative fuel sources
for residential, commercial and industrial customers and is projected to remain
so well into the future due to increasing supplies and competition. The Company
continues to advise electricity customers as to the cost advantages of
converting space and water heating needs to natural gas. Significant growth has
occurred in the Company's natural gas business in recent years due to increased
demand for natural gas in new construction. The Company also makes sales or
provides transportation service directly to large natural gas customers.
Challenges facing the Company's natural gas business include the continuing
potential for customers to by-pass the Company's natural gas system. Since
1988, two of the Company's large industrial customers have built their own
pipeline interconnections. However, these customers continue to purchase
natural gas services from the Company. To reduce the potential for such
by-pass, the Company prices its natural gas services, including transportation
contracts, competitively, and has varying degrees of flexibility to price its
transportation and delivery rates by means of special contracts. The Company
has also signed long-term transportation contracts with two of its largest
industrial customers which minimizes the chances of these customers by-passing
the Company's system in the foreseeable future.
While rate design changes have increased the costs of firm transportation to low
load-factor pipeline customers such as the Company, flexible receipt and
delivery points and capacity releases allow temporarily under-utilized
transportation to be released to others when not needed to serve the Company's
customers. The Company is also able to optimize its natural gas portfolio by
engaging in non-retail sales. Non-retail sales are made to marketers and
producers where points of delivery are outside the Company's retail distribution
area.
NATURAL GAS RESOURCES
Natural Gas Supply A diverse portfolio of resources allows the Company to
capture market opportunities that benefit the Company's natural gas
customers. Natural gas supplies are available from both domestic and Canadian
sources through both firm and short-term, or spot market, purchases. In
addition, the Company has access to five pipelines and a natural gas storage
facility which allows the Company to optimize its available resources.
Firm natural gas supplies are purchased by the Company through negotiated
agreements having terms ranging between one month and ten years with a variety
of natural gas suppliers. During 1995, approximately one-third of the Company's
purchases were in the short-term market, with contracts on a month-to-month
basis. Approximately 30% of the natural gas supply was obtained from domestic
sources, with the remaining 70% from Canadian sources.
The Company has access to five natural gas pipelines, Northwest Pipeline Company
(NWP), Pacific Gas Transmission (PGT), Paiute Pipeline (Paiute), NOVA Pipeline,
Ltd. (NOVA) and Alberta Natural Gas Co. Ltd. (ANG), which provide the Company
access to both domestic and Canadian natural gas supplies. In August 1995, the
Company obtained increased capacity on the PGT pipeline, which increases the
Company's reliance on Canadian sources of natural gas. With this resource
portfolio, the Company remains one of the nation's lowest-cost local natural gas
distribution companies.
The Company contracts with NWP for three types of firm service (transportation,
liquefied natural gas storage and underground storage) and with PGT, NOVA and
ANG for firm transportation only. The Company contracts with NOVA, ANG and PGT
for additional transportation capacity which became available in November 1995
for service in its Washington, Idaho and Oregon natural gas properties. The
Company contracts with Paiute for firm transportation and liquefied natural gas
storage to deliver natural gas to its California customers.
Jackson Prairie Natural Gas Storage Project (Storage Project) The Company owns
a one-third interest in the Storage Project, which is an underground natural gas
storage field located near Chehalis, Washington. The role of the Storage
Project in providing flexible natural gas supplies is increasingly important to
the Company's natural gas operations as it enables the Company to place natural
gas into storage when prices are low or to meet minimum natural gas purchasing
requirements, as well as to withdraw natural gas from storage when spot prices
are high or as needed to meet high demand periods. The Company, together with
the other owners, is pursuing alternatives to increase the potential for both
capacity and deliverability at the Storage Project.
The Company has contracted to release some of its Storage Project capacity to
two other utilities until 1998 and 2000, respectively, with a provision under
one of the releases to partially recall the released capacity if the Company
determines additional natural gas is required for its own system supply.
8
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THE WASHINGTON WATER POWER COMPANY
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Natural Gas Transportation Services The Company provides transportation service
to customers who obtain their own natural gas supplies. Transportation service
continued to be a significant component of the Company's total system deliveries
in 1995. The competitive nature of the spot natural gas market results in
savings in the cost of purchased natural gas, which encourages large customers
with fuel-switching capabilities to continue to utilize natural gas for their
energy needs. The total volume transported on behalf of transportation
customers was approximately 221.3 million therms in 1995. This volume
represented approximately 40% of the Company's total system deliveries in 1995.
NATURAL GAS REGULATORY ISSUES
The Company, as a public utility, is currently subject to regulation by four
state utility commissions with respect to rates, accounting, the issuance of
securities and other matters. The natural gas operations are subject to the
jurisdiction of the WUTC, the IPUC, the Public Utility Commission of Oregon
(OPUC) and the California Public Utilities Commission (CPUC) in addition to the
jurisdiction of the FERC with respect to natural gas rates charged for the
release of capacity from the Storage Project. In each jurisdiction, rates are
determined substantially as described in Electric Service - Electric Regulatory
Issues.
General Rate Cases The Company has no current plans to file for any natural
gas general rate cases in 1996. See Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations: Future Outlook for
additional information regarding rate freezes related to the proposed merger
with SPPC and SPR. The Company's most recent general natural gas rate case in
Washington was effective in August 1990 and allowed a return on equity of
12.90%. The effective change was a $1.1 million, or 2.58%, increase in
anticipated annual revenues. The Company's most recent general natural gas rate
case in Idaho was effective in October 1989 and allowed a return on equity of
12.75%. The effective change was a decrease of $0.6 million, or 3.66%, in
anticipated annual revenues. A reconsideration, effective in February of 1990,
granted a $0.1 million, or 0.86%, increase in annual revenues. In addition, the
Company from time to time, upon request, receives regulatory approval from the
WUTC, the IPUC, the OPUC and the CPUC to adjust rates to reflect changes in the
cost of purchased natural gas between general rate cases. The Company
anticipates that future rate filings will move away from rate of return
regulation toward a performance-based regulatory system.
Integrated Resource Planning (IRP) See Electric Service - Electric Regulatory
Issues for a detailed description of the IRP process. The natural gas IRP is a
process required by the WUTC, the IPUC and the OPUC. The 1995 natural gas IRP
reports were submitted to these commissions in January 1995 with acknowledgments
received at the end of 1995. The natural gas IRP is provided to the CPUC for
informational purposes only.
Notice of Inquiry (NOI) In August 1995, the WUTC initiated an NOI entitled,
"Examining Regulation of Local Distribution Companies in the Face of Change in
the Natural Gas Industry." The WUTC is seeking comments on the potential
structural change in the natural gas industry, the implications of industry
changes for utility regulation and recommendations concerning specific rules and
regulations currently used by the WUTC. The WUTC will use responses from this
inquiry to review and, if necessary, revise regulatory procedures and rules
concerning such matters as least-cost planning, purchased gas adjustment (PGA)
mechanisms and demand side management incentives. The Company provided initial
comments in September 1995 and reply comments in early February 1996, and will
participate in meetings in March of 1996 pertaining to natural gas procurement
incentives.
Demand Side Management (DSM) See Electric Service - Electric Regulatory Issues
regarding the WUTC and IPUC DSM applications. In 1993, the OPUC authorized the
Company to defer revenue requirements associated with its Oregon DSM investments
and established an annual rate adjustment mechanism to reflect the deferred
costs on a timely basis. Under this authorization, the Company files annually,
concurrent with the Company's annual natural gas tracker filing, a rate
adjustment to recover DSM program costs and margin losses. On December 1, 1995,
the OPUC approved the Company's annual tracker increase which included such a
rate adjustment.
Natural Gas Trackers Natural gas trackers are designed to pass through changes
in purchased natural gas costs and do not normally result in any changes in net
income to the Company. In October 1995, the Company filed natural gas trackers
with the WUTC, the IPUC and the OPUC. The trackers in Washington and Idaho were
both approved, effective December 22, 1995, and authorized a $10.6 million, or
13.58%, decrease and a $4.85 million, or 16.68%, decrease, respectively, in the
two jurisdictions. The Oregon natural gas tracker, which became effective on
December 1, 1995, authorized a $2.6 million, or 5.82%, decrease. A PGA, or
natural gas tracker, filing was approved by the CPUC effective January 5, 1995
which authorized a $0.8 million, or 7.71%, increase in California.
9
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THE WASHINGTON WATER POWER COMPANY
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NATURAL GAS OPERATING STATISTICS
Years Ended December 31,
1995 1994 1993
SOURCES OF SUPPLY (Thousands of Therms):
Purchases............................................... 429,903 335,780 300,572
Storage - injections.................................... (31,248) (20,518) (26,398)
Storage - withdrawals................................... 32,332 19,053 20,153
Natural gas for transportation.......................... 221,261 195,543 197,499
Distribution system gains (losses)...................... 4,923 1,471 7,416
-------- -------- --------
Total supply.......................................... 657,171 531,329 499,242
======== ======== ========
THERMS DELIVERED (Thousands of Therms):
Residential............................................. 159,919 150,106 151,261
Commercial.............................................. 120,838 120,901 114,793
Industrial - firm....................................... 14,658 15,614 19,035
Industrial - interruptible.............................. 10,621 12,801 15,747
-------- -------- --------
Total retail sales.................................... 306,036 299,422 300,836
Non-retail sales........................................ 104,831 36,107 --
Transportation.......................................... 221,261 195,543 197,499
Interdepartmental sales and Company use................. 25,043 257 907
-------- -------- --------
Total therms - sales and transportation............... 657,171 531,329 499,242
======== ======== ========
NET SYSTEM MAXIMUM CAPABILITY (Thousands of Therms):
Net system maximum demand (winter)...................... 2,758 2,686 2,651
Net system maximum firm contractual capacity (winter)... 3,523 3,523 3,523
NATURAL GAS OPERATING REVENUES (Thousands of Dollars):
Residential............................................. $84,358 $76,597 $68,137
Commercial.............................................. 52,671 50,981 43,542
Industrial - firm....................................... 5,470 5,642 6,089
Industrial - interruptible.............................. 1,967 3,570 4,784
-------- -------- --------
Total retail revenues................................. 144,466 136,790 122,552
Non-retail sales........................................ 10,530 5,098 --
Transportation.......................................... 12,340 11,140 10,923
Other revenues.......................................... 6,891 3,748 4,072
-------- -------- --------
Total natural gas revenues............................ $174,227 $156,776 $137,547
======== ======== ========
Income from natural gas operations - After income tax... $18,686 $18,495 $19,406
======== ======== ========
NUMBER OF NATURAL GAS CUSTOMERS (Average for Period):
Residential............................................. 192,252 179,176 162,400
Commercial.............................................. 24,606 23,466 22,526
Industrial - firm....................................... 281 264 268
Industrial - interruptible.............................. 31 33 39
-------- -------- --------
Total retail customers................................ 217,170 202,939 185,233
Non-retail sales........................................ 5 1 --
Transportation.......................................... 75 60 56
-------- -------- --------
Total natural gas customers........................... 217,250 203,000 185,289
======== ======== ========
NATURAL GAS RESIDENTIAL SERVICE AVERAGES:
Washington and Idaho
Annual use per customer (therms)...................... 919 899 1,025
Revenue per therm (in cents).......................... 48.98 47.46 41.55
Annual revenue per customer........................... $450.07 $426.83 $425.82
Oregon and California
Annual use per customer (therms)...................... 678 731 775
Revenue per therm (in cents).......................... 61.78 58.62 52.78
Annual revenue per customer........................... $418.88 $428.64 $409.11
HEATING DEGREE DAYS:
Spokane, WA
Actual................................................ 6,363 6,225 7,224
30 year average....................................... 6,842 6,842 6,882
% of average.......................................... 93.0 91.0 105.0
Medford, OR
Actual................................................ 3,751 4,348 4,396
30 year average....................................... 4.611 4,611 4,798
% of average.......................................... 81.3 94.3 91.6
10
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THE WASHINGTON WATER POWER COMPANY
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ENVIRONMENTAL ISSUES
The Company is subject to environmental regulation by federal, state and local
authorities. The generation, transmission, distribution, service and storage
facilities in which the Company has an ownership interest have been designed to
comply with all environmental laws presently applicable. Furthermore, the
Company conducts vigilant and periodic reviews of all its facilities and
operations to anticipate emerging environmental issues.
Air Quality. The Company continues to assess both the potential and actual
impact of the 1990 Clean Air Act Amendments (CAAA) on the thermal generating
plants in which it maintains an ownership interest. Centralia, which is operated
by PacifiCorp, is classified as a "Phase II" coal-fired plant under the CAAA
and, as such, will be required to reduce sulfur dioxide (SO2) emissions by
approximately 40% by the year 2000. The Owners are continuing to assess
alternatives for compliance to the CAAA. Results of current studies are expected
by the end of 1996. The alternatives most likely to be used in meeting the
compliance standards will be some combination of lower sulfur coal, SO2
reduction through clean coal technology and SO2 allowances either purchased or
pooled, if available, among the Centralia owners. The anticipated share of costs
for SO2 compliance are not expected to have a major economic impact on the
Company.
Colstrip, which is also a "Phase II" coal-fired plant and is operated by Montana
Power, is not expected to be required to implement any additional SO2 mitigation
in the foreseeable future in order to continue operations. Reduction in nitrogen
oxides (NOX) will be required at both Centralia and Colstrip prior to the year
2000. The anticipated share of costs for NOX compliance are not expected to have
a major economic impact on the Company.
The Company's other thermal projects also are subject to various CAAA standards.
Every five years each project requires an updated operating permit (known as a
Title V permit) which addresses, among other things, the compliance of the plant
with the CAAA. The permit for the Spokane CT was received in 1995. The permit
for the Company's Kettle Falls plant is still pending. The operating permit
application for the CTs in northern Idaho is currently under consideration. The
Company expects to be able to obtain these permits under the CAAA. See Electric
Service - Electric System for additional information.
Superfund Sites. The Company was named a potentially responsible party under
the Comprehensive Environmental Response, Compensation, and Liability Act of
1980 ("CERCLA" or "Superfund") at the Coal Creek site in Chehalis, Washington.
The clean-up is now complete, with the exception of some long-term maintenance
efforts, at a cost of approximately $14 million. The cost was shared by
approximately 90 utilities. The Company's portion, which has already been paid,
was about $1.1 million. Insurance recovery of $750,000 was received in May
1995.
The Company has been named as a potentially responsible party under CERCLA at
the Chemical Handling site near Denver, Colorado. The Company is one of
approximately 1,100 named by the EPA at this site. The site was used by the
Company for the disposal of generators. The Company expects that its share of
the cost of clean-up will be minimal.
In 1993, the EPA referred a matter to the U.S. Justice Department requesting the
Company and other potentially responsible parties to enter into negotiations for
the recovery of costs incurred by EPA and for initiation of action in connection
with the clean-up at the Spokane Junkyard Site located in Spokane, Washington.
Currently, the Justice Department and the Company have entered into an agreement
to stay litigation. If an action is commenced, the claim will be for $2.8
million plus costs, including attorneys' fees. The Company has no records
showing that any Company equipment was ever deposited at the Spokane Junkyard
Site.
The Company and several other potentially responsible parties entered into an
administrative order on consent under CERCLA to conduct an engineering
evaluation/cost analysis for the site. As of December 31, 1995, an accrued
liability of $2.0 million is reflected in the Company's financial statements
which represents the Company's best estimate of its maximum exposure for the
site.
Refer to Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations: Future Outlook and Note 14 to Financial Statements
for additional information.
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THE WASHINGTON WATER POWER COMPANY
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NON-UTILITY BUSINESS
The majority of the non-utility operations are controlled by Pentzer, a wholly
owned subsidiary of the Company. As of December 31, 1995, the Company had an
equity investment of approximately $130 million in non-utility businesses, of
which approximately $123 million was invested in Pentzer. The remainder was
invested in four other subsidiaries, the largest of which is Washington
Irrigation and Development Company (WIDCo), which maintains a small investment
portfolio.
As of December 31, 1995, Pentzer had approximately $220 million in total assets,
or about 10% of the Company's consolidated assets. Pentzer's portfolio of
investments includes companies involved in consumer product promotion, specialty
tool manufacturing, metal fabrication, financial services, electronic technology
and industrial real estate development.
Pentzer's current investment profile focuses on manufacturers and distributors
of industrial and consumer products as well as service businesses. The Company
seeks businesses with above average records of earnings growth in industries
that are not cyclical or dependent upon high levels of research and development.
Emphasis is placed on leading companies with strong market franchises, dominant
or proprietary product lines or other significant competitive advantages.
Pentzer is particularly interested in companies serving niche markets. Total
equity investment in any one company is generally limited to $15 million, and
control of the acquired company's board of directors is generally required.
Pentzer's business strategy is to acquire controlling interest in a broad range
of middle-market companies, to help these companies grow through internal
development and strategic acquisitions, and to sell the portfolio investments
either to the public or to strategic buyers when it becomes most advantageous in
meeting Pentzer's return on invested capital objectives. Pentzer's goal is to
produce financial returns for the Company's shareholders that, over the
long-term, should be higher than that of the utility operations. From time to
time, a significant portion of Pentzer's earnings contributions may be the
result of transactional gains. Accordingly, although the income stream is
expected to be positive, it may be uneven from year to year.
Refer to Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations: Results of Operations: Non-Utility Operations and
Notes 1 and 15 to Financial Statements for additional information.
12
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THE WASHINGTON WATER POWER COMPANY
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ITEM 2. PROPERTIES
ELECTRIC PROPERTIES
The Company's electric properties, located in the States of Washington, Idaho
and Montana, include the following:
Generating Plant
Nameplate Present Year of
No. of Rating Capability FERC License
Units (MW)(1) (MW)(2) Expiration
--------- ------- ---------- ------------
Hydroelectric Generating Stations (River)
Washington:
Long Lake (Spokane) 4 70.0 72.0 2007
Little Falls (Spokane) 4 32.0 36.0 N/A
Nine Mile (Spokane) 4 26.4 29.0 2007
Upper Falls (Spokane) 1 10.0 10.2 2007
Monroe Street (Spokane) 1 14.8 14.8 2007
Meyers Falls (Colville) 2 1.2 1.3 2023
Idaho:
Cabinet Gorge (Clark Fork) 4 221.9 236.0 2001 (3)
Post Falls (Spokane) 6 14.8 18.0 2007
Montana:
Noxon Rapids (Clark Fork) 5 466.7 554.0 2005 (3)
------- -------
Total Hydroelectric 857.8 971.3
Thermal Generating Stations
Washington:
Centralia (4) 2 199.5 201.0
Kettle Falls 1 50.7 48.0
Northeast (Spokane) CT (5) 2 61.2 69.0
Idaho:
Rathdrum CT (5), (6) 2 166.5 176.0
Montana:
Colstrip (Units 3 and 4) (4) 2 233.4 216.0
------- -------
Total Thermal 711.3 710.0
Total Generation 1,569.1 1,681.3
======= =======
N/A Not applicable.
(1) Nameplate Rating, also referred to as "installed capacity", is the
manufacturer's assigned power rating under specified conditions.
(2) Capability is the maximum generation of the plant without exceeding
approved limits of temperature, stress and environmental conditions.
(3) The formal relicensing process began in September 1995 for Cabinet Gorge and
Noxon Rapids.
(4) Jointly-owned; data above refers to Company's respective 15% interests.
(5) Used primarily for peaking needs.
(6) Construction completed in January 1995; see Note 9 to Financial Statements
regarding long-term lease financing.
Distribution and Transmission Plant
The Company operates approximately 11,350 miles of primary and secondary
distribution lines in its electric system in addition to a transmission system
of approximately 550 miles of 230 KV line and 1,545 miles of 115 KV line. The
Company also owns a 10% interest in 495 miles of a 500 KV line from Colstrip,
Montana and a 15% interest in 3 miles of a 500 KV line from Centralia,
Washington to the nearest Bonneville Power Administration (BPA)
interconnections.
The 230 KV lines are used primarily to transmit power from the Company's Noxon
Rapids and Cabinet Gorge hydroelectric generating stations to major load
centers in the Company's service area. The 230 KV lines also transmit to
points of interconnection with adjoining electric transmission systems for bulk
power transfers. These lines interconnect with BPA at five locations and at one
location each with PacifiCorp, Montana Power and Idaho Power Company. The BPA
13
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THE WASHINGTON WATER POWER COMPANY
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interconnections serve as points of delivery for power from the Colstrip and
Centralia generating stations as well as for the interchange of power with the
Southwest. The interconnection with PacifiCorp is the point of delivery for
power purchased by the Company from Mid-Columbia projects' hydroelectric
generating stations.
The 115 KV lines provide for transmission of energy as well as providing for the
integration of the Spokane River hydroelectric and Kettle Falls wood-waste
generating stations with service area load centers. These lines interconnect
with the BPA at nine locations, Grant County Public Utility District (PUD),
Seattle City Light and Tacoma City Light at two locations and one interconnect
location each with Chelan County PUD, PacifiCorp and Montana Power.
NATURAL GAS PROPERTIES
The Company's natural gas properties have natural gas distribution mains of
approximately 3,250 miles in Washington and Idaho and 1,550 miles in Oregon and
California, as of December 31, 1995.
The Company, NWP and Washington Natural Gas Company each own a one-third
undivided interest in the Storage Project, which has a total peak day
deliverability of 4.6 million therms, with a total working natural gas inventory
of 155.2 million therms.
ITEM 3. LEGAL PROCEEDINGS
Refer to Note 14 to Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
14
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THE WASHINGTON WATER POWER COMPANY
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Outstanding shares of Common Stock are listed on the New York and Pacific Stock
Exchanges. As of February 29, 1996, there were approximately 33,138
registered shareholders of the Company's no par value Common Stock.
See Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations: Future Outlook for additional information about common
stock dividends.
Refer to Notes 1, 5 and 17 to Financial Statements for additional information.
15
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THE WASHINGTON WATER POWER COMPANY
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ITEM 6. SELECTED FINANCIAL DATA
On November 9, 1993, the Company distributed, to shareholders of record on
October 25, 1993, shares of its common stock, without par value, under a
two-for-one stock split effected in the form of a 100% stock dividend. All
references to number of shares and per share information have been adjusted to
reflect the common stock split on a retroactive basis.
The Company purchased natural gas distribution properties in Oregon and
California from CP National Corporation on September 30, 1991. The 1991
financial information reflects three months of operations of these properties.
On July 31, 1990, WIDCo sold its 50% interest in its coal mining properties. The
consolidated financial statements, notes and selected financial data have been
reclassified to reflect the continuing operations of the Company. The revenues,
expenses, assets and liabilities of the discontinued operations have been
reclassified from those categories and netted into single line items in the
income statements and balance sheets.
Years Ended December 31,
--------------------------------------------------------------
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
(Thousands of Dollars except Per Share Data and Ratios)
Operating Revenues:
Utility .............................. $ 661,216 $ 608,067 $ 601,722 $ 524,983 $ 485,075
Non-Utility .......................... 93,793 62,698 38,877 32,775 81,732
---------- ---------- ---------- ---------- ----------
Total ................................ 755,009 670,765 640,599 57,758 566,807
AFUDC/AFUCE ............................ 1,631 4,949 4,964 3,751 1,999
Net Income:
Utility .............................. 72,310 63,567 69,510 63,975 69,211
Non-Utility .......................... 14,811 13,630 13,266 8,292 1,420
Discontinued Operations .............. - - - 2,403 1,553
---------- ---------- ---------- ---------- ----------
Total ................................ 87,121 77,197 82,776 74,670 72,184
Preferred Stock Dividend Requirements 9,123 8,656 8,335 6,817 9,292
Income Available for Common Stock ...... 77,998 68,541 74,441 67,853 62,892
Outstanding Common Stock (000s):
Weighted Average ..................... 55,173 53,538 51,616 49,550 46,916
Year-End ............................. 55,948 54,421 52,758 50,888 47,902
Book Value per Share ................... $ 12.82 $ 12.45 $ 12.02 $ 11.54 $ 11.11
Earnings per Share:
Utility .............................. 1.14 1.03 1.19 1.15 1.28
Non-Utility .......................... .27 .25 .25 .17 .03
Discontinued operations .............. - - - .05 .03
---------- ---------- ---------- ---------- ----------
Total ................................ 1.41 1.28 1.44 1.37 1.34
Dividends Paid per Common Share ........ 1.24 1.24 1.24 1.24 1.24
Total Assets at Year-End:
Utility .............................. 1,872,391 1,820,671 1,701,652 1,424,812 1,394,800
Non-Utility .......................... 226,511 173,582 136,186 109,203 126,713
---------- ---------- ---------- ---------- ----------
Total ................................ 2,098,902 1,994,253 1,837,838 1,534,015 1,521,513
Long-term Debt at Year-End ............. 738,287 721,146 647,229 596,897 633,434
Preferred Stock Subject to Mandatory
Redemption at Year-End ............... 85,000 85,000 85,000 85,000 50,000
Ratio of Earnings to Fixed Charges ..... 3.22 3.24 3.45 3.08 2.96
Ratio of Earnings to Fixed Charges and
Preferred Dividend Requirements ...... 2.61 2.59 2.77 2.57 2.35
16
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THE WASHINGTON WATER POWER COMPANY
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The Company is primarily engaged as a utility in the generation, purchase,
transmission, distribution and sale of electric energy and the purchase,
transportation, distribution and sale of natural gas. Natural gas operations
are affected to a significant degree by weather conditions and customer growth.
The Company's electric operations are highly dependent upon hydroelectric
generation for its power supply. As a result, the electric operations of the
Company are significantly affected by weather and streamflow conditions and, to
a lesser degree, by customer growth. Revenues from the sale of surplus energy
to other utilities and the cost of power purchases vary from year to year
depending on streamflow conditions and the wholesale power market. The
wholesale power market in the Northwest region is affected by several factors,
including the availability of water for hydroelectric generation, the
availability of base load plants in the region and the demand for power in the
Southwest region. Other factors affecting the wholesale power market include
new entrants in the wholesale market, such as power brokers and marketers, and
competition from low cost generation being developed by independent power
producers. Usage by retail customers varies from year to year primarily as a
result of weather conditions, the economy in the Company's service area,
customer growth, conservation, appliance efficiency and other technology.
RESULTS OF OPERATIONS
OVERALL OPERATIONS
Overall earnings per share for 1995 were $1.41, compared to $1.28 in 1994 and
$1.44 in 1993. The 1995 results include improved earnings from the Company's
electric operations and $6.1 million in transactional gains from Pentzer
Corporation (Pentzer), primarily due to the sale of stock in ITRON, Inc.
(ITRON). The 1994 earnings include $8.0 million of gains recorded by Pentzer
primarily as a result of the sale of ITRON stock. The 1993 results include
gains totaling $12.8 million recorded by Pentzer as a result of the sale of
several investments in its portfolio and the sale of stock in the initial public
offering by ITRON in November 1993.
Utility income available for common stock increased $8.3 million, or 15%, in
1995 after decreasing $6.3 million, or 10%, in 1994. Utility income contributed
$1.14 to earnings per share in 1995, compared to $1.03 in 1994 and $1.19 in
1993. Non-utility income available for common stock increased $1.2 million in
1995 and $0.4 million in 1994 and contributed $0.27 to earnings per share in
1995 and $0.25 in 1994 and 1993.
Income from electric operations increased $17.2 million, or 18%, in 1995 over
1994, primarily due to increased wholesale revenues, resulting from both new
power contracts and improved streamflow conditions, and decreased purchased
power and fuel expense, both a result of the improved streamflows. Income from
natural gas operations increased $0.2 million in 1995 over 1994. During 1995,
increased natural gas revenues, which were primarily the result of customer
growth, were nearly offset by increased purchased gas costs and other operating
expenses. Weather that was 9% warmer than normal during 1994 reduced
residential usage for both electric and natural gas customers. Income from
electric operations increased $0.1 million in 1994 over 1993 primarily as a
result of decreased purchased power expense. Income from natural gas operations
decreased $0.9 million in 1994, as compared to 1993, due primarily to increased
purchased gas costs that were offset substantially by increased revenues due to
customer growth.
Interest expense increased $5.9 million in 1995, as compared to 1994, and $2.9
million in 1994, as compared to 1993, with both increases primarily due to
higher levels of outstanding debt and a shift from short-term debt to long-term
debt and the resulting higher interest rates. During 1995 and 1994, $78.0
million and $88.0 million, respectively, in long-term debt was issued, while
$45.0 million and $7.5 million, respectively, of long-term debt matured or was
redeemed. At December 31, 1995, long-term debt outstanding was $17.1 million
higher than at December 31, 1994. Long-term debt outstanding at December 31,
1994, was $73.9 million higher than at the end of 1993.
Other Income decreased in 1995 over 1994, primarily due to lower levels of
Allowance for Funds Used During Construction (AFUDC) and other capitalized
interest, as a result of lower levels of construction and conservation program
expenditures. (See Note 1 to Financial Statements for additional information
about AFUDC.) Also contributing to the decline in Other Income were the accrual
for environmental remediation work (see Note 14 to Financial Statements for
additional information) and amortization of the acquisition adjustment from the
Company's purchase of PacifiCorp's electric properties in northern Idaho in late
December 1994.
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UTILITY OPERATIONS
REVENUES
Electric revenues increased in all classes for 1995, as compared to 1994.
Wholesale revenues increased $17.8 million, or 20%, in 1995, primarily due to
new power contracts for firm service and increased secondary sales, as a result
of improved streamflow conditions which led to increased availability of
hydroelectric generation in the region, and generation from the Rathdrum
combustion turbine which went into service in January 1995. Residential and
commercial revenues increased by a combined $18.8 million, primarily as a result
of an increase of nearly 16,500 customers, or 6%, during 1995. Approximately
10,000 residential and commercial customers were added through the acquisition
of PacifiCorp's electric properties in northern Idaho in late December 1994.
Electric revenues decreased by 3% in 1994, as compared to 1993, due to a
combination of decreased residential sales and wholesale sales, partially offset
by increased commercial sales and higher wheeling revenues. Wholesale revenues
decreased $17.2 million during 1994, compared to 1993, primarily due to a
significant short-term sale of wholesale energy in 1993 which increased
wholesale revenues in that period, low streamflow conditions during 1994 which
led to decreased KWh sales and lower wholesale prices. Residential revenues for
1994 decreased by $7.0 million from 1993, despite a 3% increase in customers,
due to warm weather throughout most of the year. Residential usage continues to
be affected by new appliance efficiency and other technology which has decreased
customers' requirements over time. Commercial revenues increased $5.0 million,
or 4%, in 1994, as compared to 1993, due to 3% customer growth and the slightly
warmer-than-normal weather which increased air conditioning load. Commercial
customers tend to use air conditioning systems at much cooler temperatures than
residential customers, with the result that air conditioning load can be up
within the commercial sector and not within the residential sector, as during
the fall of 1994.
Total natural gas revenues increased $17.5 million, or 11%, in 1995, which was
the result of increased therm sales of 24% in 1995. Residential and commercial
revenues increased by a combined $9.5 million in 1995 as compared to 1994,
primarily as a result of 7% customer growth in those sectors, primarily due to
conversions from electric service to natural gas, population growth and new
construction. During 1995, the Company sold natural gas on a non-retail sales
basis, which accounted for a $5.4 million increase in total revenues. The
revenues from these sales were offset by like increases in purchased gas
expense. Margins from these transactions are credited back to customers through
rate changes for the cost of gas. Transportation sales increased by 13%,
leading to a $1.2 million increase in revenues.
Total natural gas revenues increased in all customer classes except industrial
in 1994 compared to 1993. In 1994, natural gas revenues from residential and
commercial customers rose by $8.5 million and $7.4 million, respectively. The
increased revenues were due to customer growth and higher average prices than in
1993, which were offset in part by lower usage per customer as a result of warm
temperatures. Much of the customer growth during the early part of 1994 was the
result of the Company's emphasis on conversions from electric service to natural
gas. Revisions in the Company's Demand Side Management programs in 1994 have
lessened the pace of conversions. During 1994, the Company began selling
natural gas on a non-retail sales basis, which resulted in a $5.1 million
increase in revenues and a like increase in purchased gas expense.
OPERATING EXPENSES
Improved streamflow conditions, which resulted in increased hydroelectric
generation, caused purchased power expense for 1995 to decline by $8.6 million
from 1994. Hydroelectric generation was 105% above normal, due to streamflows
which were 120% of normal in 1995. Purchased power costs in 1994 decreased
$12.5 million, or 11%, from levels incurred during 1993, primarily due to
increased purchases during 1993 to complete a significant short-term sale of
wholesale energy and to replace lost thermal generation due to plant outages.
Hydroelectric generation in 1994 was 23% below normal, caused by streamflows
which were 65% of normal.
Fuel costs decreased $6.9 million in 1995 compared to 1994 as a result of the
increased availability of hydroelectric generation. The decreased thermal plant
fuel expense was partially offset by fuel expense for generation from the
Rathdrum combustion turbines, particularly in the last half of the year. Fuel
costs increased $4.9 million in 1994 over 1993 due to increased thermal
generation as a result of the low streamflows in 1994 and shutdowns at thermal
plants during 1993 which decreased fuel expense for that year.
A large portion of purchased gas expense is variable costs, with the result that
increases in revenues are generally offset by like increases in purchased gas
expense. Natural gas purchased expense increased $11.1 million, or 12%, in 1995
as compared to 1994, primarily as the result of an increase in therm sales of
125.8 million, or 24%. Increases
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in therm sales were primarily due to customer growth in all customer classes and
non-retail sales. Natural gas purchased expense increased $19.4 million in 1994
from 1993, which was the result of increased therm sales of 32.1 million therms.
Other electric operating and maintenance expenses increased $19.6 million in
1995 primarily due to lease payments and operating expenses related to the
Rathdrum combustion turbine, increased amortization of conservation programs, a
higher accrual for uncollectible accounts, environmental remediation reserves
(see Note 14 to Financial Statements for additional information) and the Idaho
Power Cost Adjustment (PCA), which allows the Company to change rates to recover
or rebate a portion of the difference between actual and allowed net power
supply costs. Net PCA adjustments, resulting from improved streamflow
conditions, accounted for $5.8 million of the increase in other operating and
maintenance expenses in 1995 from 1994. Net PCA adjustments, resulting from low
hydroelectric conditions, accounted for $4.1 million of the decrease in other
operating and maintenance expenses in 1994 from 1993. Transmission and
distribution costs decreased by a combined $3.3 million in 1994, as a result of
decreased wholesale KWh sales and the associated wheeling costs, which also
contributed to the decrease in other operating and maintenance expenses from the
1993 levels.
Administrative and general expenses increased by $5.3 million in 1995, compared
to 1994, primarily due to lease payments for computer software systems, labor
expenses resulting from merger activities and other labor-related costs.
Administrative and general expenses increased by $3.7 million in 1994 over 1993,
primarily due to labor-related cost increases.
Depreciation and amortization expense increased $2.7 million in 1995, primarily
due to increased plant-in-service, particularly natural gas plant. During 1994,
depreciation and amortization expense increased $1.0 million due to increased
electric plant.
Other taxes, primarily excise and business and occupational taxes, were up $1.3
million in 1995 over 1994 due to increased revenues in 1995.
Income taxes increased by $9.9 million, or 26%, in 1995, as a result of
increased income from electric operations. Electric operations accounted for
$8.7 million of the increase. Income tax expense decreased $3.2 million in 1994
as compared to 1993 primarily due to decreased income from electric operations.
NON-UTILITY OPERATIONS
Non-utility operations include the results of Pentzer and four other subsidiary
companies. Pentzer's business strategy is to acquire controlling interests in a
broad range of middle-market companies, to help these companies grow through
internal development and strategic acquisitions and to sell the portfolio
investments either to the public or to strategic buyers when it becomes most
advantageous in meeting Pentzer's return on invested capital objectives.
Pentzer's goal is to produce financial returns for the Company's shareholders
that, over the long-term, should be higher than that of the utility operations.
From time to time, a significant portion of Pentzer's earnings contributions may
be the result of transactional gains. Accordingly, although the income stream
is expected to be positive, it may be uneven from year to year.
Non-utility net income for 1995 was $14.8 million, which represents a 9%
increase over 1994 earnings of $13.6 million. The increase in 1995 earnings
primarily resulted from a $2.2 million increase in non-transactional earnings
over 1994 as a result of improved earnings from companies in Pentzer's
investment portfolio, including earnings from two companies newly acquired in
1995. Non-utility operating revenues and expenses both increased substantially
in 1995 as compared to 1994 as a result of acquisitions over the past two years.
Non-utility net income for 1994 increased 3% over 1993 earnings. The increase
in 1994 earnings primarily resulted from improved earnings from companies in
Pentzer's investment portfolio, including earnings from newly acquired
companies. Non-utility operating revenues and expenses both increased
substantially in 1994 as compared to 1993 as a result of acquisitions during
both 1994 and 1993.
Transactional gains in 1995 declined by $1.1 million as compared to 1994.
Transactional gains of $8.0 million in 1994 declined by $4.8 million as compared
to 1993. The 1995 and 1994 transactional gains were primarily the result of
gains recorded from the sale of ITRON stock. The 1993 transactional gains
included gains of $7.1 million from the sale of companies involved in
telecommunications, technology and energy and a transactional gain of $5.7
million from the sale of ITRON stock.
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LIQUIDITY AND CAPITAL RESOURCES
UTILITY
The Company funds capital expenditures with a combination of
internally-generated cash and external financing. The level of cash generated
internally and the amount that is available for capital expenditures fluctuates
annually. Cash provided by operating activities remains the Company's primary
source of funds for operating needs, dividends and construction expenditures.
Operating Activities Cash from operating activities less cash dividends paid
provided 83% of utility capital expenditures in 1995 as compared to 66% in 1994
and 67% in 1993. Cash available from operating activities in 1995 declined from
1994 primarily due to increases in deferred taxes and various working capital
components, such as receivables, materials and supplies, fuel stock and natural
gas stored and prepayments on power contracts, partially offset by the positive
effect of purchased gas deferrals. However, as discussed below, construction
expenditures declined by 13% in 1995 from 1994 so that cash from operating
activities provided a higher percentage of the funds for construction than in
the two previous years. See Note 1 to Financial Statements for additional
information.
Investing Activities Cash used in investing activities decreased in 1995 over
1994 primarily due to the acquisition of the northern Idaho properties of
PacifiCorp for $33 million in 1994 and a $22 million decrease in other capital
requirements, which included conservation-related capital expenditures. Utility
capital expenditures, excluding Allowance for Funds Used During Construction
(AFUDC) and Allowance for Funds Used to Conserve Energy (AFUCE, a carrying
charge similar to AFUDC for conservation-related capital expenditures), were
$338 million for the 1993-1995 period.
Financing Activities During the 1993-1995 period, $95.0 million of long-term
debt matured and $231.6 million of higher-cost debt and preferred stock was
redeemed and refinanced at lower cost. During 1995, $45 million of long-term
debt, with an average interest rate of 7.19%, matured and $78 million of First
Mortgage Bonds issued in the form of Secured Medium-Term Notes were issued at an
average interest rate of 7.1% and an average maturity of 8 years.
Capital expenditures are financed on an interim basis with notes payable (due
within one year). The Company has $160 million in committed lines of credit.
In addition, the Company may borrow up to $60 million through other borrowing
arrangements with banks. As of December 31, 1995, $19.5 million was outstanding
under the committed lines of credit and $10.0 million was outstanding under
other short-term borrowing arrangements.
From time to time the Company enters into sale/leaseback arrangements for
various long-term assets which provide additional sources of funds. See Note 9
to Financial Statements for additional information.
The Company is restricted under various agreements as to the additional
securities it can issue. Under the most restrictive test of the Company's
Mortgage, an additional $524 million of First Mortgage Bonds could be issued as
of December 31, 1995. As of December 31, 1995, under its Restated Articles of
Incorporation, approximately $673 million of additional preferred stock could be
issued at an assumed dividend rate of 7.25%.
During the 1996-1998 period, utility capital expenditures are expected to be
$237 million, and $90 million will be required for long-term debt maturities and
preferred stock sinking fund requirements. During this three-year period, the
Company estimates that internally-generated funds will average 95% of the funds
needed for its capital expenditure program. Minimal amounts of external
financing will be required to fund maturing long-term debt, preferred stock
sinking fund requirements and the remaining portion of capital expenditures.
These estimates of capital expenditures are subject to continuing review and
adjustment. Actual capital expenditures may vary from these estimates due to
factors such as changes in business conditions, construction schedules and
environmental requirements. These projections relate to the Company on a
stand-alone basis and do not reflect any adjustment for the effects of the
proposed merger of the Company, Sierra Pacific Resources (SPR) and Sierra
Pacific Power Company (SPPC) with and into Altus Corporation (Altus). See
Future Outlook - Merger below.
See Notes 4, 5, 6, 7, 8 and 9 to Financial Statements for additional details
related to financing activities.
NON-UTILITY
Capital expenditures for the non-utility operations were $13 million for the
1993-1995 period. During this period, $9 million of debt was repaid and capital
expenditures were partially financed by the $14 million in proceeds from new
long-term debt.
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The non-utility operations have $48 million in short-term borrowing arrangements
($26.6 million outstanding as of December 31, 1995) to fund corporate
requirements on an interim basis. At December 31, 1995, the non-utility
operations had $32.2 million in cash and marketable securities with $28.5
million in long-term debt outstanding.
The 1996-1998 non-utility capital expenditures are expected to be $6 million,
and $21 million in debt maturities will also occur. During the next three
years, internally-generated cash and other debt obligations are expected to
provide the majority of the funds for the non-utility capital expenditure
requirements.
TOTAL COMPANY CASH REQUIREMENTS
(Millions of Dollars) Actual (1) Projected (2)
------------------ ------------------
1993 1994 1995 1996 1997 1998
---- ---- ---- ---- ---- ----
Capital Expenditures (3):
Utility:
Electric $ 60 $ 57 $ 45 $45 $48 $48
Natural gas 26 27 26 23 20 23
All other 49 39 9 9 10 11
---- ---- ---- --- --- ---
Total Utility 135 123 80 77 78 82
Non-Utility 3 9 5 2 2 2
---- ---- ---- --- --- ---
Total Company $138 $132 $ 85 $79 $80 $84
==== ==== ==== === === ===
Debt and Preferred Stock Maturities,
Redemptions & Sinking Fund
Requirements (Consolidated) (4): $274 $ 8 $ 45 $47 $43 $21
(1) Excludes $62 million for the combustion turbine project located in Rathdrum,
Idaho for which the Company has obtained separate long-term lease
financing; see Note 9 to Financial Statements for additional
information. Also excludes $33 million in 1994 for the acquisition of
the northern Idaho electric properties of PacifiCorp.
(2) These projections relate to the Company on a stand-alone basis and do not
reflect any adjustment for the effects of the proposed merger of the
Company, SPR and SPPC with and into Altus.
(3) Excludes AFUDC and AFUCE.
(4) Excludes notes payable (due within one year).
The Company's total common equity increased by $40 million to $717 million at
the end of 1995. The 1995 increase was primarily due to the issuance of 1.5
million shares of common stock through both the Dividend Reinvestment Plan and
the Investment and Employee Stock Ownership Plan for proceeds of $24.0 million
and a $10.2 million increase in retained earnings. The Company's consolidated
capital structure at December 31, 1995, was 46% debt, 9% preferred stock and 45%
common equity as compared to 47% debt, 9% preferred stock and 44% common equity
at year-end 1994.
FUTURE OUTLOOK
Merger
In June 1994, the Company, Sierra Pacific Resources (SPR), Sierra Pacific Power
Company, a subsidiary of SPR (SPPC), and Altus Corporation (Altus, formerly
named Resources West Energy Corporation), a newly formed subsidiary of the
Company, entered into an Agreement and Plan of Reorganization and Merger, as
subsequently amended (Merger Agreement), which provides for the merger of the
Company, SPR and SPPC into Altus. SPR and SPPC are both Nevada corporations
with headquarters in Reno. The Merger Agreement provides that after the
effective date of the merger, Altus' corporate headquarters office and principal
executive offices will be located in Spokane and that the headquarters of the
Washington Water Power and Sierra Pacific operating divisions will be in Spokane
and Reno, respectively. As a result of the Merger Agreement, holders of WWP
Common Stock would receive one share and holders of SPR Common Stock would
receive 1.44 shares of Altus Common Stock, respectively. Each outstanding share
of Preferred Stock of WWP and SPPC, respectively, will be converted into the
right to receive one share of Altus Preferred Stock with equal stated value and
dividends and like redemption provisions and rights upon liquidation.
Approval of the proposed merger was obtained from WWP, SPR and SPPC shareholders
at meetings held on November 18, 1994. The Merger Agreement is also subject to
certain customary closing conditions, including
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without limitation, the receipt of all necessary governmental approvals,
including approval of the Federal Energy Regulatory Commission (FERC) and the
state utility commissions of California (CPUC), Idaho (IPUC), Montana (MPSC),
Nevada (PSCN), Oregon (OPUC) and Washington (WUTC). Applications were filed
with each of the state commissions and the FERC in the third quarter of 1994.
The MPSC issued an order in October 1994 declining to exercise jurisdiction.
The Company has received orders approving the merger from the commissions of
each state. The major points of each order are as follows:
Washington: Order approving the merger was issued on September 28, 1995
Electric and gas base rate freeze through December 31, 2000
Purchased gas benefits flowed through annual Purchased Gas
Adjustment (PGA)
Accelerated amortization of Washington electric DSM to provide
full amortization by December 31, 2003
On October 17, 1995, the Commission stayed the effectiveness
of the September 28, 1995 order, so as to allow its staff
and Public Counsel the opportunity to review and evaluate
the order of the Nevada Commission; this stay was
subsequently lifted by order of the Commission dated
December 5, 1995. The amended WUTC order states that if the
use of single-system pricing information by any other
jurisdiction or the inter-divisional compensation for use of
transmission facilities affects allocation of revenues,
expenses, rate base or cost of capital to the detriment of
Washington ratepayers, such effects will not be reflected in
Washington results of operations for any purpose. The
amended WUTC order states that "shareholders are at risk
for any differences if there are costs that are made
unrecoverable by this prohibition."
Idaho: Order approving the merger was issued on September 19, 1995
Electric and gas base rate freeze through December 31, 2000
Purchased gas benefits flowed through annual PGA
Earnings capped at 12.0% ROE, with earnings above 12.0% shared
50/50 with customers through the PGA/PCA (Power Cost
Adjustment)
Oregon: Order approving the merger was issued on June 23, 1995
No rate freeze
Purchased gas benefits flowed through annual PGA, plus a
sharing of non-purchased gas benefits to partially offset
the expenses associated with additional transmission
capacity on Pacific Gas Transmission facilities to Medford
California: Order approving the merger was issued on October 18, 1995
Electric and gas base rate freeze through December 31, 1999
All electric and gas tracking mechanisms suspended during the
rate freeze. Balances in the electric and gas tracking
accounts will be set to zero upon merger. Exempt from annual
electric and gas cost of capital proceedings
Electric rate reduction of $3.1 million in 1996 related to the
suspension of the electric tracking mechanism and
elimination of the balances in the tracking accounts
On February 12, 1996, SPR and the Company filed a petition for
an Order of the Commission modifying its October 18, 1995
Order, so as to extend the date by which both companies
would otherwise be obligated to submit additional regulatory
filings, including general rate case filings, in the event
the merger was not consummated by March 31, 1996
Nevada: Order approving the merger was issued on October 18, 1995
Electric and gas base rate freeze through December 31, 1999.
Water rates frozen through December 31, 1996
Gas tracker suspended through January 1, 1997. Electric
power/fuel cost tracker suspended through December 31, 1999
One-time refunds related to a prior rate stipulation of $9
million electric and $4 million gas. Earnings for 1997-1999
capped at 12.0% ROE, with earnings above 12.0% shared 50/50
with customers. On October 25, 1995, the Company and SPR
filed a petition with the PSCN requesting clarification of
their order. The companies sought clarification on two key
issues within the PSCN's order. The two issues were
electric single-system pricing for retail services and the
distribution of benefits related to the
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Alturas transmission project. On November 20, 1995, the
PSCN issued an order denying the petition for clarification.
On November 29, 1995, the FERC ordered evidentiary hearings concerning the
proposed merger. Issues raised by the FERC primarily revolve around
single-system versus zonal transmission rates, pricing for inter-divisional
energy transfers, justification of cost savings and the effects on competition,
including access by third-party users to the merged company's transmission
system, the resolution of which could have an impact on the level of anticipated
savings. (See Competition and Business Risk below for additional information on
the issuance of the FERC's policy statement in the forthcoming rulemaking on
transmission access and pricing.) An administrative law judge has been assigned
to the merger proceeding and a pre-hearing conference was held on December 13,
1995 to set a procedural schedule. The companies filed supplemental testimony
on February 1, 1996. Hearings are scheduled to begin on June 4, 1996. Based on
this schedule, the companies believe an order could be issued by the FERC in
1996 or early 1997.
Most of the final orders issued by state commissions include a "reopener" clause
that allows the state proceedings to be reopened if any party believes that the
FERC or any other state commission has taken some action which makes the
Stipulation in such state undesirable.
If closing conditions contained in the Merger Agreement are not satisfied or
in the event that the merger is not closed on or before June 27, 1996 and
either of the parties exercises its right of termination any time thereafter
as provided in the Merger Agreement, the Company would continue to operate
as a separate utility and expense the merger costs that were incurred.
See Note 16 to Financial Statements for additional information.
Competition and Business Risk
The electric and natural gas utility businesses continue to undergo numerous
transformations and are becoming increasingly competitive as a result of
economic, regulatory and technological changes. The Company believes that it is
well positioned to meet future challenges due to its low production costs, close
proximity to major transmission lines and natural gas pipelines, active
participation in the wholesale electric market and its commitment to high levels
of customer satisfaction, cost reduction and continuous improvement of work
processes. Additionally, the Company continually evaluates merger and
acquisition opportunities that will allow it to expand its economies of scale
and diversify its risk posed by weather and economic conditions.
The Company continues to compete for new retail electric customers with various
rural electric cooperatives and public utility districts in and adjacent to its
service territories. Challenges facing the electric business include the
potential for retail wheeling, the costs of increasingly stringent environmental
laws and the potential for stranded or nonrecoverable utility assets.
Challenges facing the electric retail business include evolving technologies
which provide alternate energy supplies, reduced energy consumption and the cost
of the energy supplied, self-generation and fuel switching by commercial and
industrial customers. If electric utility companies are eventually required to
provide retail wheeling service, which is the transmission of electric power
from another supplier to a customer located within such utility's service area,
the Company believes it will be in a position to benefit since it is committed
to remaining one of the country's lowest-cost providers of electric energy.
Consequently, the Company believes it faces minimal risk for stranded
generation, transmission or distribution assets due to its low cost structure.
The National Energy Policy Act (NEPA) enacted in 1992 addresses a wide range of
issues affecting the wholesale electric business. The Company believes NEPA
provides future transmission, energy production and sales opportunities to the
Company and complements the Company's commitment to the wholesale electric
business.
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking (NOPR)
relating to transmission services and a supplemental NOPR on Recovery of
Stranded Costs. If adopted, the NOPR on open access transmission would require
public utilities operating under the Federal Power Act to provide third-party
access to their transmission systems. Each utility would also be required to
establish separate rates for its transmission and generation services for new
wholesale service. Further, utilities would be required to take transmission
service under the same tariffs applicable to third-party users. The FERC
requested comments on the desirability of unified standards for both wholesale
and retail transmission services. The FERC suggested, as a possible approach,
the establishment by each vertically integrated electric utility of a
distribution function which would be treated as a wholesale customer taking
transmission services under the utility's filed wholesale transmission tariff.
The FERC recognized, and numerous comments confirmed, that such an approach
would change the traditional approach of state-federal allocation of
transmission costs. The supplemental NOPR on stranded costs provides a basis for
recovery by regulated public
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THE WASHINGTON WATER POWER COMPANY
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utilities of legitimate and verifiable stranded costs associated with existing
wholesale requirements customers and retail customers who become unbundled
wholesale transmission customers of the utility. The FERC will consider allowing
recovery of stranded investment costs associated with retail wheeling only if a
state regulatory commission lacks the authority to consider that issue. It is
anticipated that the final rules could take effect in the first half of 1996.
The Company does not believe that the Open Access NOPR will have a material
effect on the Company's results of operations, assuming that the final rule is
adopted substantially as proposed. However, if, in the pending or a subsequent
rule-making proceeding, the FERC adopted a rule which had the effect of
requiring the wholesale transmission rate to be recognized as the transmission
component of retail rates, and if the FERC imposed single-system transmission
rates on Altus in the Merger proceeding, this could lead to a reduction of
Altus' retail rates in Nevada but would not necessarily result in a
corresponding increase in Washington and Idaho.
The Company continues to compete in the wholesale electric market with other
western utilities, federal marketing agencies and power marketers. Business
challenges affecting the wholesale electric business include new entrants in the
wholesale market, such as power brokers and marketers, competition from low-cost
generation being developed by independent power producers and declining margins.
Natural gas remains priced competitively compared to other alternative fuel
sources for residential, commercial and industrial customers and is projected to
remain so well into the future due to increasing supplies and competition.
Challenges facing the Company's natural gas business include the potential for
customers to by-pass the Company's natural gas system. Since 1988, two of the
Company's large industrial customers have built their own pipeline
interconnection. However, these customers continue to purchase natural gas
services from the Company. To reduce the potential for such by-pass, the
Company prices its natural gas services, including transportation contracts,
competitively and has varying degrees of flexibility to price its transportation
and delivery rates by means of special contracts. The Company has also signed
long-term transportation contracts with two of its largest industrial customers
which minimizes the risks of these customers by-passing the Company's system in
the foreseeable future.
Resource planning for both the electric and natural gas businesses has been
integrated so that the Company's customers are provided the most efficient and
cost-effective products possible for all their energy requirements. The
Company's need for future electric resources to serve retail loads is expected
to remain very minimal. The switching of electric heating customers to natural
gas requires increased efforts on the Company's part in negotiating and securing
competitively-priced natural gas supplies for the future.
Economic and Load Growth
The Company expects economic growth to increase in its eastern Washington and
northern Idaho service area. The Company, along with others in the service
area, continues its efforts to expand existing businesses and attract new
businesses to the Inland Northwest. In the past, agriculture, mining and lumber
have been the primary industries. However, health care, electronic and other
manufacturing, tourism and the service sectors have become increasingly
important industries that operate in the Company's service area. In addition,
the Company also anticipates strong economic growth to continue in its Oregon
service area.
The Company anticipates electric retail load growth to average approximately
1.4% annually for the next five years primarily due to increases in both
population and the number of businesses in its service territory. Although the
number of electric customers is expected to increase, the average annual usage
by residential customers is expected to remain stable on a weather-adjusted
basis.
The Company anticipates natural gas load growth, including transportation
volumes, in its Washington and Idaho service area to average approximately 3.1%
annually for the next five years. The Oregon and South Lake Tahoe, California
service areas are anticipated to realize 3.2% growth annually during that same
period.
The forward-looking projections set forth above regarding retail sales growth
are based, in part, upon publicly available population and demographic studies
conducted independently. The Company's expectations regarding retail sales
growth are also based upon various assumptions including, without limitation,
assumptions relating to weather and economic and competitive conditions and an
assumption that the Company will incur no material loss of retail customers due
to self-generation or retail wheeling. Changes in the underlying assumptions
can cause actual experience to vary significantly from forward-looking
projections.
24
28
THE WASHINGTON WATER POWER COMPANY
================================================================================
Environmental Issues
Since December 1991, a number of species of fish in the Northwest, including the
Snake River sockeye salmon and chinook salmon, the Kootenai River white sturgeon
and the bull trout have either been added to the endangered species list under
the Federal Endangered Species Act (ESA), listed as "threatened" under the ESA
or been petitioned for listing under the ESA. Thus far, measures which have
been adopted and implemented to save both the Snake River sockeye salmon and
chinook salmon have not directly impacted generation levels at any of the
Company's hydroelectric dams. The Company does, however, purchase power from
four projects on the Columbia River that are being directly impacted by these
ongoing mitigation measures. The reduction in generation at these projects is
relatively minor, resulting in minimal economic impact on the Company at this
time. Future actions to save these, and other as yet unidentified fish or
wildlife species, could further impact the Company's operations or the
operations of some of its major customers. However, it is currently impossible
to predict likely economic costs to the Company resulting from these actions.
See Note 14 to Financial Statements for additional information.
Other
The Board of Directors considers the level of dividends on the Company's common
stock on a continuing basis, taking into account numerous factors including,
without limitation, the Company's results of operations and financial condition,
as well as general economic and competitive conditions. The Company's net
income available for dividends are derived from its retail electric and natural
gas utility operations and, increasingly, from its growing wholesale electric
operations and Pentzer's non-utility investment operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Independent Auditor's Report and Financial Statements begin on the next
page.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
25
29
INDEPENDENT AUDITORS' REPORT
The Washington Water Power Company
Spokane, Washington
We have audited the accompanying consolidated balance sheets and statements of
capitalization of The Washington Water Power Company and subsidiaries (the
Company) as of December 31, 1995 and 1994, and the related consolidated
statements of income and retained earnings, cash flows, and the schedules of
information by business segments for each of the three years in the period ended
December 31, 1995. These financial statements and schedules are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and schedules 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 and schedules are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements and
schedules. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement and schedule presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements and schedules present
fairly, in all material respects, the financial position of the Company and its
subsidiaries at December 31, 1995 and 1994, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1995, in conformity with generally accepted accounting principles. In
addition, the schedules referred to above present fairly, in all material
respects, the segment information of the Company and its subsidiaries in
accordance with generally accepted accounting principles.
Deloitte & Touche LLP
Seattle, Washington
January 26, 1996 (March 1, 1996 as to Note 15)
26
30
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
The Washington Water Power Company
================================================================================
For the Years Ended December 31
Thousands of Dollars
1995 1994 1993
------- -------- --------
OPERATING REVENUES............................. $755,009 $670,765 $640,599
-------- -------- --------
OPERATING EXPENSES:
Operations and maintenance................... 388,119 350,703 322,117
Administrative and general................... 62,486 59,645 55,083
Depreciation and amortization................ 67,572 59,479 58,354
Taxes other than income taxes................ 46,992 45,480 44,195
-------- -------- --------
Total operating expenses................... 565,169 515,307 479,749
-------- -------- --------
INCOME FROM OPERATIONS......................... 189,840 155,458 160,850
-------- -------- --------
OTHER INCOME (EXPENSE):
Interest expense............................. (59,022) (53,077) (50,133)
Net gain on subsidiary transactions.......... 9,328 11,519 9,915
Other income (deductions)-net................ (609) 7,993 4,647
-------- -------- --------
Total other income (expense)-net........... (50,303) (33,565) (35,571)
-------- -------- --------
INCOME BEFORE INCOME TAXES..................... 139,537 121,893 125,279
INCOME TAXES................................... 52,416 44,696 42,503
-------- -------- --------
NET INCOME..................................... 87,121 77,197 82,776
DEDUCT-Preferred stock dividend requirements... 9,123 8,656 8,335
-------- -------- --------
INCOME AVAILABLE FOR COMMON STOCK.............. $ 77,998 $ 68,541 $ 74,441
======== ======== ========
Average common shares outstanding (thousands).. 55,173 53,538 51,616
EARNINGS PER SHARE OF COMMON STOCK............. $ 1.41 $ 1.28 $ 1.44
Dividends paid per common share................ $ 1.24 $ 1.24 $ 1.24
RETAINED EARNINGS, JANUARY 1................... $114,848 $112,424 $101,644
NET INCOME..................................... 87,121 77,197 82,776
DIVIDENDS DECLARED:
Preferred stock.............................. (8,971) (8,823) (8,219)
Common stock................................. (68,392) (66,378) (64,209)
ESOP dividend tax savings...................... 425 428 432
-------- -------- --------
RETAINED EARNINGS, DECEMBER 31................. $125,031 $114,848 $112,424
======== ======== ========
The Accompanying Notes are an Integral Part of These Statements.
27
31
CONSOLIDATED BALANCE SHEETS
The Washington Water Power Company
================================================================================
At December 31
Thousands of Dollars
1995 1994
---------- ----------
ASSETS:
UTILITY PLANT-Original Cost:
Electric-net.............................................. $1,523,387 $1,477,998
Natural Gas............................................... 341,947 316,974
Common plant.............................................. 38,332 34,624
---------- ----------
Utility plant........................................... 1,903,666 1,829,596
Less accumulated depreciation and amortization:
Electric................................................ 429,891 394,559
Natural Gas............................................. 106,129 97,217
Common plant............................................ 10,228 8,775
---------- ----------
Net utility plant..................................... 1,357,418 1,329,045
---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Investment in exchange power-net.......................... 82,252 88,615
Non-utility properties and investments.................... 135,612 100,174
Other-net................................................. 9,593 13,971
---------- ----------
Total other property and investments.................... 227,457 202,760
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents................................. 5,164 5,178
Temporary cash investments................................ 27,395 27,928
Accounts and notes receivable-net......................... 102,389 74,524
Materials and supplies, fuel stock and natural gas stored. 38,004 21,384
Prepayments and other..................................... 11,020 7,552
---------- ----------
Total current assets.................................... 183,972 136,566
---------- ----------
DEFFERRED CHARGES:
Regulatory assets for deferred income tax................. 169,432 174,349
Conservation programs..................................... 62,793 66,511
Prepaid power purchases................................... 32,605 13,680
Unamortized debt expense.................................. 25,684 28,406
Other-net................................................. 39,541 42,936
---------- ----------
Total deferred charges.................................. 330,055 325,882
---------- ----------
TOTAL................................................. $2,098,902 $1,994,253
========== ==========
CAPITALIZATION AND LIABILITIES:
CAPITALIZATION (See Consolidated Statements of
Capitalization)........................................... $1,590,412 $1,533,640
---------- ----------
CURRENT LIABILITIES:
Accounts payable.......................................... 64,841 46,217
Taxes and interest accrued................................ 39,415 28,931
Other..................................................... 64,703 58,541
---------- ----------
Total current liabilities............................... 168,959 133,689
---------- ----------
DEFERRED CREDITS:
Deferred income taxes..................................... 307,529 310,167
Other..................................................... 32,002 16,757
---------- ----------
Total deferred credits.................................. 339,531 326,924
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 9, 13 and 14)
TOTAL................................................. $2,098,902 $1,994,253
========== ==========
The Accompanying Notes are an Integral Part of These Statements.
28
32
CONSOLIDATED STATEMENTS OF CAPITALIZATION
The Washington Water Power Company
================================================================================
At December 31
Thousands of Dollars
1995 1994
---- ----
COMMON EQUITY:
Common stock, no par value; 200,000,000 shares authorized:
shares outstanding: 1995-55,947,967; 1994-54,420,696....................... $ 594,636 $ 570,603
Note receivable from employee stock ownership plan........................... (11,690) (12,267)
Capital stock expense and other paid in capital.............................. (10,072) (10,031)
Unrealized investment gain-net............................................... 19,220 14,341
Retained earnings............................................................ 125,031 114,848
---------- ----------
Total common equity........................................................ 717,125 677,494
---------- ---------
PREFERRED STOCK-CUMULATIVE:
10,000,000 shares authorized:
Not subject to mandatory redemption:
Flexible Auction Series J; 500 shares outstanding ($100,000 stated value).. 50,000 50,000
---------- ----------
Total not subject to mandatory redemption................................ 50,000 50,000
---------- ----------
Subject to mandatory redemption:
$8.625 Series I; 500,000 shares outstanding ($100 stated value)............ 50,000 50,000
$6.95 Series K; 350,000 shares outstanding ($100 stated value)............. 35,000 35,000
---------- ----------
Total subject to mandatory redemption.................................... 85,000 85,000
---------- ----------
LONG-TERM DEBT:
First Mortgage Bonds:
4 5/8% due March 1, 1995................................................... -- 10,000
7 1/8% due December 1, 2013................................................ 66,700 66,700
7 2/5% due December 1, 2016................................................ 17,000 17,000
Secured Medium-Term Notes:
Series A - 4.72% to 8.06% due 1996 through 2023.......................... 250,000 250,000
Series B - 6.50% to 8.25% due 1997 through 2010.......................... 141,000 63,000
---------- ----------
Total first mortgage bonds............................................... 474,700 406,700
---------- ----------
Pollution Control Bonds:
6% Series due 2023......................................................... 4,100 4,100
Unsecured Medium-Term Notes:
Series A - 7.94% to 9.58% due 1997 through 2007............................ 72,500 92,500
Series B - 5.50% to 8.55% due 1996 through 2023............................ 135,000 150,000
---------- ----------
Total unsecured medium-term notes........................................ 207,500 242,500
---------- ----------
Notes payable (due within one year) to be refinanced......................... 29,500 58,000
Other........................................................................ 22,487 9,846
---------- ----------
Total long-term debt....................................................... 738,287 721,146
---------- ----------
TOTAL CAPITALIZATION........................................................... $1,590,412 $1,533,640
========== ==========
The Accompanying Notes are an Integral Part of These Statements.
29
33
CONSOLIDATED STATEMENTS OF CASH FLOWS
Increase (Decrease) in Cash and Cash Equivalents
The Washington Water Power Company
================================================================================
For the Years Ended December 31
Thousands of Dollars
1995 1994 1993
---- ---- ----
OPERATING ACTIVITIES:
Net income....................................................... $ 87,121 $ 77,197 $ 82,776
NON-CASH ITEMS INCLUDED IN NET INCOME:
Depreciation and amortization.................................. 67,572 59,479 58,354
Provision for deferred income taxes............................ (5,487) 15,380 6,962
Allowance for equity funds used during construction............ (589) (1,261) (1,666)
Power and natural gas cost deferrals and amortizations......... 16,156 6,365 (7,624)
Deferred revenues and other.................................... 9,600 5,971 6,968
(Increase) decrease in working capital components:
Receivables and prepaid expense.............................. (22,279) (12,458) 1,116
Materials & supplies, fuel stock and natural gas stored...... (11,733) (1,864) (2,001)
Payables and other accrued liabilities....................... 21,532 4,343 (1,846)
Other........................................................ (29,661) (8,309) 8,767
-------- --------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES.......................... 132,232 144,843 151,806
-------- --------- ---------
INVESTING ACTIVITIES:
Construction expenditures (excluding AFUDC-equity funds)......... (83,494) (95,815) (111,118)
Other capital requirements....................................... 550 (21,603) (30,216)
(Increase) decrease in other noncurrent balance sheet items-net.. 8,893 (21,686) (1,063)
Assets acquired and investments in subsidiaries.................. (13,864) (43,823) 2,725
-------- --------- ---------
NET CASH USED IN INVESTING ACTIVITIES.............................. (87,915) (182,927) (139,672)
-------- --------- ---------
FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings..................... (28,500) (10,001) 64,001
Proceeds from issuance of long-term debt......................... 78,000 88,000 254,100
Redemption and maturity of long-term debt........................ (45,000) (7,500) (274,100)
Sale of common stock............................................. 12,518 14,934 25,899
Redemption premiums.............................................. -- -- (9,595)
Other............................................................ 4,150 10,051 (7,819)
-------- --------- ---------
NET FINANCING ACTIVITIES BEFORE CASH DIVIDENDS..................... 21,168 95,484 52,486
Less cash dividends paid......................................... (65,499) (63,423) (61,773)
-------- --------- ---------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES................ (44,331) 32,061 (9,287)
-------- --------- ---------
NET INCREASE (DECREASE) IN CASH & CASH EQUIVALENTS................. (14) (6,023) 2,847
CASH & CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 5,178 11,201 8,354
-------- --------- ---------
CASH & CASH EQUIVALENTS AT END OF PERIOD........................... $ 5,164 $ 5,178 $ 11,201
======== ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period:
Interest....................................................... $ 53,415 $ 46,861 $ 47,854
Income taxes................................................... $ 50,004 $ 34,094 $ 35,649
Noncash financing and investing activities....................... $ 87,763 $ 25,891 $ 13,327
The Accompanying Notes are an Integral Part of These Statements.
30
34
SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS
The Washington Water Power Company
================================================================================
For the Years Ended December 31
Thousands of Dollars
1995 1994 1993
---------- ---------- ----------
OPERATING REVENUES:
Electric........................................ $ 486,989 $ 451,291 $ 464,175
Natural Gas..................................... 174,227 156,776 137,547
Non-utility..................................... 93,793 62,698 38,877
---------- ---------- ----------
Total operating revenues...................... $ 755,009 $ 670,765 $ 640,599
========== ========== ==========
OPERATIONS AND MAINTENANCE EXPENSES:
Electric:
Power purchased............................... $ 97,669 $ 106,277 $ 118,809
Fuel for generation........................... 32,298 39,176 34,233
Other electric................................ 80,834 61,268 68,567
Natural Gas:
Natural gas purchased for resale.............. 102,375 91,277 71,867
Other natural gas............................. 15,655 14,297 14,286
Non-utility..................................... 59,288 38,408 14,355
---------- ---------- ----------
Total operations and maintenance expenses..... $ 388,119 $ 350,703 $ 322,117
========== ========== ==========
ADMINISTRATIVE AND GENERAL EXPENSES:
Electric........................................ $ 39,087 $ 35,190 $ 32,376
Natural Gas..................................... 12,351 10,944 10,069
Non-utility..................................... 11,048 13,511 12,638
---------- ---------- ----------
Total administrative and general expenses..... $ 62,486 $ 59,645 $ 55,083
========== ========== ==========
DEPRECIATION AND AMORTIZATION EXPENSES:
Electric........................................ $ 49,499 $ 48,233 $ 47,003
Natural Gas..................................... 9,670 8,199 8,470
Non-utility..................................... 8,403 3,047 2,881
---------- ---------- ----------
Total depreciation and amortization expenses.. $ 67,572 $ 59,479 $ 58,354
========== ========== ==========
INCOME FROM OPERATIONS:
Electric........................................ $ 150,988 $ 125,125 $ 128,166
Natural Gas..................................... 25,356 23,926 24,942
Non-utility..................................... 13,496 6,407 7,742
---------- ---------- ----------
Total income from operations.................. $ 189,840 $ 155,458 $ 160,850
========== ========== ==========
INCOME AVAILABLE FOR COMMON STOCK:
Utility operations.............................. $ 63,187 $ 54,911 $ 61,175
Non-utility operations.......................... 14,811 13,630 13,266
---------- ---------- ----------
Total income available for common stock ...... $ 77,998 $ 68,541 $ 74,441
========== ========== ==========
ASSETS:
Electric........................................ $1,440,560 $1,441,643 $1,372,128
Natural Gas..................................... 274,408 247,060 220,253
Common plant.................................... 28,104 25,849 27,572
Other utility assets............................ 129,319 106,118 81,699
Non-utility assets.............................. 226,511 173,583 136,186
---------- ---------- ----------
Total assets.................................. $2,098,902 $1,994,253 $1,837,838
========== ========== ==========
CAPITAL EXPENDITURES (excluding AFUDC/AFUCE):
Electric........................................ $ 44,656 $ 70,791 $ 84,277
Natural Gas..................................... 25,939 32,682 30,774
Common plant.................................... 9,349 19,262 19,801
Non-utility..................................... 4,934 8,701 3,452
---------- ---------- ----------
Total capital expenditures.................... $ 84,878 $ 131,436 $ 138,304
========== ========== ==========
The Accompanying Notes are an Integral Part of These Statements.
31
35
THE WASHINGTON WATER POWER COMPANY
================================================================================
NOTES TO FINANCIAL STATEMENTS
================================================================================
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
The Company was incorporated in the State of Washington in 1889, and is
primarily engaged as a utility in the generation, purchase, transmission,
distribution and sale of electric energy and the purchase, transportation,
distribution and sale of natural gas. Natural gas operations are affected to a
significant degree by weather conditions and customer growth. The Company's
electric operations are highly dependent upon hydroelectric generation for its
power supply. As a result, the electric operations of the Company are
significantly affected by weather and streamflow conditions and, to a lesser
degree, by customer growth. Revenues from new wholesale contracts and the sale
of surplus energy to other utilities and the cost of power purchases vary from
year to year depending on streamflow conditions and the wholesale power market.
The wholesale power market in the Northwest region is affected by several
factors, including the availability of water for hydroelectric generation, the
availability of base load plants in the region and the demand for power in the
Southwest region. Other factors affecting the wholesale power market include
new entrants in the wholesale market, such as power brokers and marketers, and
competition from low cost generation being developed by independent power
producers. Usage by retail customers varies from year to year primarily as a
result of weather conditions, the economy in the Company's service area,
customer growth, conservation, appliance efficiency and other technology.
BASIS OF REPORTING
The financial statements are presented on a consolidated basis and, as such,
include the assets, liabilities, revenues and expenses of The Washington Water
Power Company (Company) and its wholly owned subsidiaries, Pentzer Corporation
(Pentzer), Washington Irrigation and Development Company (WIDCo), Altus
Laboratories, Altus Energy Solutions and WP Finance Company. All material
intercompany transactions have been eliminated in the consolidation. As
discussed in Note 15, the 1993 and 1994 operating results for ITRON were
accounted for on the equity method; however, as of December 31, 1994, Pentzer's
investment in ITRON is classified as available for sale and recorded at fair
value on the Consolidated Balance Sheets. The accompanying financial statements
include the Company's proportionate share of utility plant and related
operations resulting from its interests in jointly owned plants (See Note 3).
The financial activity of each of the Company's segments is reported in the
"Schedule of Information by Business Segments." Such information is an integral
part of these financial statements.
The preparation of the Company's consolidated financial statements in conformity
with generally accepted accounting principles necessarily requires management to
make estimates and assumptions that directly affect the reported amounts of
assets, liabilities, revenues and expenses.
SYSTEM OF ACCOUNTS
The accounting records of the Company's utility operations are maintained in
accordance with the uniform system of accounts prescribed by the Federal Energy
Regulatory Commission (FERC) and adopted by the appropriate state regulatory
commissions.
REGULATION
The Company is subject to state regulation in Washington, Idaho and Montana for
its electric operations. Natural gas operations are regulated in Washington,
Idaho, Oregon and California. The Company is subject to regulation by the
FERC with respect to its wholesale electric transmission rates and the natural
gas rates charged for the release of capacity from the Jackson Prairie Storage
Project.
OPERATING REVENUES
The Company accrues estimated unbilled revenues for electric and natural gas
services provided through month-end.
32
36
THE WASHINGTON WATER POWER COMPANY
================================================================================
OTHER INCOME-NET
Other income-net is composed of the following items:
Years Ended December 31,
---------------------------------
1995 1994 1993
---- ---- ----
(Thousands of Dollars)
Interest income .......................... $ 3,645 $ 3,535 $ 4,058
Capitalized interest (debt) .............. 1,042 3,687 3,027
Gain (loss) on property dispositions ..... 1,272 738 (1,370)
Equity earnings in subsidiary companies .. - 1,774 1,653
Minority interest ........................ (314) (289) (1,273)
Capitalized interest (equity) ............ 589 1,261 1,666
Other .................................... (6,843) (2,713) (3,114)
------- ------- -------
Total ............................... $ (609) $ 7,993 $ 4,647
======= ======= =======
EARNINGS PER SHARE
Earnings per share have been computed based on the weighted average number of
common shares outstanding during the period.
UTILITY PLANT
The cost of additions to utility plant, including an allowance for funds used
during construction and replacements of units of property and betterments, is
capitalized. Costs of depreciable units of property retired plus costs of
removal less salvage are charged to accumulated depreciation.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The Allowance for Funds Used During Construction (AFUDC) represents the cost of
both the debt and equity funds used to finance utility plant additions during
the construction period. In accordance with the uniform system of accounts
prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost
of utility plant and is credited currently as a noncash item to Other Income
(see Other Income above). The Company generally is permitted, under established
regulatory rate practices, to recover the capitalized AFUDC, and a fair return
thereon, through its inclusion in rate base and the provision for depreciation
after the related utility plant has been placed in service. Cash inflow related
to AFUDC does not occur until the related utility plant investment is placed in
service.
The effective AFUDC rate was 10.67% in 1995, 1994 and 1993. The Company's AFUDC
rates do not exceed the maximum allowable rates as determined in accordance with
the requirements of regulatory authorities.
DEPRECIATION
For utility operations, depreciation provisions are estimated by a method of
depreciation accounting utilizing unit rates for hydroelectric plants and
composite rates for other properties. Such rates are designed to provide for
retirements of properties at the expiration of their service lives. The rates
for hydroelectric plants include annuity and interest components, in which the
interest component is 6%. For utility operations, the ratio of depreciation
provisions to average depreciable property was 2.57% in 1995, 2.56% in 1994 and
2.68% in 1993.
CASH AND CASH EQUIVALENTS
For the purposes of the Consolidated Statements of Cash Flows, the Company
considers all temporary investments with an initial maturity of three months or
less to be cash equivalents.
TEMPORARY INVESTMENTS
Under FAS No. 115, "Accounting for Certain Investments in Debt and Equity
Securities," investments in debt and marketable equity securities are classified
as "available for sale" and are recorded at fair value. Investments totaling
$37.1 million and $27.4 million are included on the Consolidated Balance Sheets
at December 31, 1995 as other property and investments and current assets,
respectively. Investments totaling $34.1 million and $27.9 million are included
on the Consolidated Balance Sheets at December 31, 1994 as other property and
investments and current assets, respectively. Unrealized investment gains, as
of December 31, 1995 and 1994, of $19.2 million and $14.3 million, respectively,
net of taxes, are reflected as a separate component of shareholders' equity on
the Consolidated Statements of Capitalization.
DERIVATIVE FINANCIAL INSTRUMENTS
The Company has used derivative instruments to a limited extent as a means of
hedging its costs and preserving margins in the wholesale power business. The
extent of derivatives used through the end of 1995 is not
33
37
THE WASHINGTON WATER POWER COMPANY
================================================================================
significant. The Company may continue to use derivative instruments for hedging
and risk mitigation purposes, but has adopted a policy not to trade in
derivatives for speculative reasons.
DEFERRED CHARGES AND CREDITS
The Company prepares its financial statements in accordance with the provisions
of FAS No. 71, "Accounting for the Effects of Certain Types of Regulation." A
regulated enterprise can prepare its financial statements in accordance with FAS
No. 71 only if (i) the enterprise's rates for regulated services are established
by or subject to approval by an independent third-party regulator, (ii) the
regulated rates are designed to recover the enterprise's cost of providing the
regulated services and (iii) in view of demand for the regulated services and
the level of competition, it is reasonable to assume that rates set at levels
that will recover the enterprise's costs can be charged to and collected from
customers. FAS No. 71 requires a cost-based, rate-regulated enterprise to
reflect the impact of regulatory decisions in its financial statements. In
certain circumstances, FAS No. 71 requires that certain costs and/or obligations
(such as incurred costs not currently recovered through rates, but expected to
be so recovered in the future) be reflected in a deferral account in the balance
sheet and not be reflected in the statement of income or loss until matching
revenues are recognized. If at some point in the future the Company determines
that it no longer meets the criteria for continued application of FAS No. 71 to
all or a portion of the Company's regulated operations, the Company would be
required to write off its regulatory assets and would be precluded from the
future deferral in the Consolidated Balance Sheet of costs not recovered through
rates at the time such costs were incurred, even if such costs were expected to
be recovered in the future.
The Company's primary regulatory assets include Investment in Exchange Power,
conservation programs, deferred income taxes, the provision for postretirement
benefits, unrecovered purchased gas costs and debt issuance and redemption
costs. Included in Deferred Charges, Other are merger transaction and
transition costs. Deferred credits include the gain on the general office
building sale/leaseback being amortized over the life of the lease.
POWER AND NATURAL GAS COST ADJUSTMENT PROVISIONS
In 1989, the Idaho Public Utilities Commission (IPUC) approved the Company's
filing for a power cost adjustment mechanism (PCA). The PCA is designed to
allow the Company to modify electric rates to recover or rebate a portion of the
difference between actual and allowed net power supply costs. On July 18, 1994,
the IPUC approved an indefinite extension of the Company's proposed
modifications to the PCA. The modified PCA tracks changes in hydroelectric
generation, secondary prices, related changes in thermal generation and PURPA
contracts, but it no longer tracks changes in revenues or cost associated with
other wheeling or power contracts. Rate changes are triggered when the deferred
balance reaches $2.2 million. As of December 31, 1995, $0.7 million of credits
not yet subject to a rebate had accumulated in the PCA deferral account. The
following surcharges were in effect during the past three years:
$2.3 million (2.4%) surcharge effective September 1, 1995, which will
expire August 31, 1996
$2.2 million (2.5%) surcharge effective January 1, 1995, which expired
December 31, 1995
$2.3 million (2.6%) surcharge effective November 1, 1992, which expired
October 31, 1993
Under established regulatory practices, the Company is also allowed to adjust
its natural gas rates from time to time to reflect increases or decreases in the
cost of natural gas purchased. Differences between actual natural gas costs and
the natural gas costs allowed in rates are deferred and charged or credited to
expense when regulators approve inclusion of the cost changes in rates.
INCOME TAXES
The Company and its eligible subsidiaries file consolidated federal income tax
returns. Subsidiaries are charged or credited with the tax effects of their
operations on a stand-alone basis. The Company's federal income tax returns
have been examined with all issues resolved, and all payments made, through
the 1992 return.
NEW ACCOUNTING STANDARDS
FAS No. 121, entitled "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of," was issued by the Financial Accounting
Standards Board (FASB), and is effective for fiscal years beginning after
December 15, 1995. FAS No. 121 requires the review of certain assets for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. If an asset is determined
to be impaired, a loss is recognized. The Company will adopt the standard on
January 1, 1996, but does not expect any material impact on the Company's
financial position or results of operations. The Company will continue to
periodically review its assets to determine whether any assets meet the
requirements for impairment recognition under this standard.
34
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THE WASHINGTON WATER POWER COMPANY
================================================================================
FAS No. 123, entitled "Accounting for Stock-Based Compensation," which is
effective for fiscal years beginning after December 15, 1995, addresses the
recommended accounting and disclosure for stock-based employee compensation
plans. The Company will adopt the standard on January 1, 1996, but will
continue to measure stock-based compensation according to Accounting Principles
Board Opinion (APB) 25.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform to current
statement format. These reclassifications were made for comparative purposes
and have not affected previously reported total net income or common
shareholders' equity.
NOTE 2. PROPERTY, PLANT AND EQUIPMENT
The year-end balances of the major classifications of property, plant and
equipment are detailed in the following table (dollars in thousands):
At December 31,
----------------------
1995 1994
---- ----
Electric:
Production........................................... $ 691,192 $ 678,356
Transmission......................................... 248,587 238,912
Distribution......................................... 510,489 458,867
Construction work in progress (CWIP) and other....... 73,119 101,863
---------- ----------
Electric total..................................... 1,523,387 1,477,998
---------- ----------
Natural Gas:
Underground storage.................................. 16,385 14,946
Transmission......................................... 3,060 3,090
Distribution......................................... 276,295 253,830
CWIP and other....................................... 46,207 45,108
---------- ----------
Natural Gas total.................................. 341,947 316,974
---------- ----------
Common plant (including CWIP)........................ 38,332 34,624
---------- ----------
Total utility...................................... 1,903,666 1,829,596
Non-utility.......................................... 60,498 56,466
---------- ----------
Total.............................................. $1,964,164 $1,886,062
========== ==========
NOTE 3. JOINTLY OWNED ELECTRIC FACILITIES
The Company has invested in several jointly owned generating plants. Financing
for the Company's ownership in the projects is provided by the Company. The
Company's share of related operating and maintenance expenses for plants in
service is included in corresponding accounts in the Consolidated Statements of
Income. The following table indicates the Company's percentage ownership and
the extent of the Company's investment in such plants at December 31, 1995:
Company's Current Share of
----------------------------------------------------------------
KW of Construction
Installed Fuel Ownership Plant in Accumulated Net Plant Work in
Project Capacity Source (%) Service Depreciation In Service Progress
- ------- --------- ------ --------- -------- ------------ ---------- ------------
(Thousands of Dollars)
Centralia .......... 1,330,000 Coal 15% $ 55,197 $32,683 $ 22,514 $1,337
Colstrip 3 & 4 ..... 1,556,000 Coal 15 272,338 88,205 184,133 -
35
39
THE WASHINGTON WATER POWER COMPANY
================================================================================
NOTE 4. ACCOUNTS RECEIVABLE SALE
The Company has entered into an agreement whereby it can sell without recourse,
on a revolving basis, up to $40,000,000 of interests in certain accounts
receivable, both billed and unbilled. The Company is obligated to pay fees
which approximate the purchaser's cost of issuing commercial paper equal in
value to the interests in receivables sold. The amount of such fees is included
in operating expenses. At both December 31, 1995 and 1994, $40,000,000 in
receivables had been sold pursuant to the agreement.
NOTE 5. COMMON STOCK
In April 1990, the Company sold 1,000,000 shares of its common stock to the
Trustee of the Investment and Employee Stock Ownership Plan for Employees of the
Company (Plan) for the benefit of the participants and beneficiaries of the
Plan. In payment for the shares of Common Stock, the Trustee issued a
promissory note payable to the Company in the amount of $14,125,000. Dividends
paid on the stock held by the Trustee, plus Company contributions to the Plan,
if any, are used by the Trustee to make interest and principal payments on the
promissory note. The balance of the promissory note receivable from the Trustee
($11,690,250 at December 31, 1995) is reflected as a reduction to common equity.
The shares of Common Stock are allocated to the accounts of participants in the
Plan as the note is repaid. During 1995, the cost recorded for the Plan was
$2,857,000. This included the cost for an additional 304,353 shares which were
issued for ongoing employee and Company contributions to the Plan. Interest on
the note payable to the Company, cash and stock contributions to the Plan and
dividends on the shares held by the Trustee were $1,146,000, $2,350,000 and
$1,215,000, respectively.
In February 1990, the Company adopted a shareholder rights plan, which was
subsequently amended, pursuant to which holders of Common Stock outstanding on
March 2, 1990, or issued thereafter, have been granted one preferred share
purchase right (Right) on each outstanding share of Common Stock. Each Right,
initially evidenced by and traded with the shares of Common Stock, entitles the
registered holder to purchase one two-hundredth of a share of Preferred Stock of
the Company, without par value, at an exercise price of $40, subject to certain
adjustments, regulatory approval and other specified conditions. The Rights
will be exercisable only if a person or group acquires 10% or more of the Common
Stock or announces a tender offer, the consummation of which would result in the
beneficial ownership by a person or group of 10% or more of the Common Stock.
The Rights may be redeemed, at a redemption price of $0.005 per Right, by the
Board of Directors of the Company at any time until any person or group has
acquired 10% or more of the Common Stock. The Rights will expire on the earlier
of February 16, 2000 or the effective time of the merger with Sierra Pacific
Resources (SPR), Sierra Pacific Power Company (SPPC) and Altus Corporation
(Altus). See Note 16 for additional information about the proposed merger.
During 1992, the Company received authorization to issue 1.5 million shares of
Common Stock under a second Periodic Offering Program (POP). In 1993, 576,400
shares of the POP were issued for net proceeds of $11.2 million. Through
December 31, 1993, 927,600 shares of the POP were issued for net proceeds of
$17.3 million. No shares were issued under the POP during 1994 or 1995. At
December 31, 1995, 572,400 shares remained authorized but unissued.
The Company has a Dividend Reinvestment and Stock Purchase Plan under which the
Company's stockholders may automatically reinvest their dividends and make
optional cash payments for the purchase of the Company's Common Stock at current
market value.
Sales of Common Stock for 1995, 1994 and 1993 are summarized below (in thousands
of dollars):
1995 1994 1993
-------------------- -------------------- --------------------
Shares Amount Shares Amount Shares Amount
---------- -------- ---------- -------- ---------- --------
Balance at January 1................ 54,420,696 $570,603 52,757,545 $544,609 50,888,130 $508,202
---------- -------- ---------- -------- ---------- --------
Employee Investment Plan (401-K)... 304,353 4,718 272,278 4,302 165,335 3,216
Dividend Reinvestment Plan......... 1,222,918 19,315 1,390,873 21,692 1,127,680 21,779
Periodic Offering.................. - - - - 576,400 11,412
---------- -------- ---------- -------- ---------- --------
Total Issues....................... 1,527,271 24,033 1,663,151 25,994 1,869,415 36,407
---------- -------- ---------- -------- ---------- --------
Balance at December 31.............. 55,947,967 $594,636 54,420,696 $570,603 52,757,545 $544,609
========== ======== ========== ======== ========== ========
36
40
THE WASHINGTON WATER POWER COMPANY
================================================================================
NOTE 6. PREFERRED STOCK
CUMULATIVE PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION:
The dividend rate on Flexible Auction Preferred Stock, Series J is reset every
49 days based on an auction. During 1995, the dividend rate varied from 4.410%
to 5.150% and at December 31, 1995, was 5.150%. Series J is subject to
redemption at the Company's option at a redemption price of 100% per share plus
accrued dividends.
CUMULATIVE PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION:
Redemption requirements:
$8.625, Series I - On June 15, 1996, 1997, 1998, 1999 and 2000, the
Company must redeem 100,000 shares at $100 per share plus
accumulated dividends. The Company may, at its option, redeem up to
100,000 shares in addition to the required redemption on any
redemption date.
$6.95, Series K - On September 15, 2002, 2003, 2004, 2005 and 2006,
the Company must redeem 17,500 shares at $100 per share plus
accumulated dividends through a mandatory sinking fund. Remaining
shares must be redeemed on September 15, 2007. The Company has the
right to redeem an additional 17,500 shares on each September 15
redemption date.
There are $50 million in mandatory redemption requirements during the 1996-2000
period.
The fair value of the Company's preferred stock at December 31, 1995 and 1994 is
estimated to be $139.8 million, or 104% of the carrying value and $135.1
million, or 100% of the carrying value, respectively. These estimates are based
on available market information.
NOTE 7. LONG-TERM DEBT
The annual sinking fund requirements and maturities for the next five years for
First Mortgage Bonds outstanding at December 31, 1995 are as follows:
Year Ended Sinking Fund
December 31 Maturities Requirements Total
----------- ---------- ------------ -----
(Thousands of Dollars)
1996.......... $35,000 $4,747 $39,747
1997.......... 31,000 4,547 35,547
1998.......... 10,000 4,437 14,437
1999.......... 47,500 4,437 51,937
2000.......... 35,000 4,287 39,287
The sinking fund requirements may be met by certification of property additions
at the rate of 167% of requirements. All of the utility plant is subject to the
lien of the Mortgage and Deed of Trust securing outstanding First Mortgage
Bonds.
In 1993, $25,000,000 of Unsecured Medium-Term Notes were issued. At December
31, 1995, the Company had outstanding $207,500,000 of such notes with maturities
between 1 and 28 years and with interest rates varying between 5.50% and 9.58%.
In 1995, 1994 and 1993, $78,000,000, $88,000,000 and $225,000,000, respectively,
of First Mortgage Bonds in the form of Secured Medium-Term Notes were issued.
At December 31, 1995, the Company had outstanding $391,000,000 of such notes
with maturities between 1 and 28 years and with interest rates varying between
4.72% and 8.25%. As of December 31, 1995, the Company had remaining
authorization to issue up to $109,000,000.
At December 31, 1995, the Company had $29,500,000 outstanding under borrowing
arrangements which will be refinanced in 1996. See Note 8 for details of credit
agreements.
37
41
THE WASHINGTON WATER POWER COMPANY
================================================================================
Included in other long-term debt are the following related to non-utility
operations (in thousands of dollars):
Outstanding at December 31
--------------------------
1995 1994
------- -------
Notes payable - variable rates through 1999............. $24,372 $12,518
Industrial revenue bonds - variable rate through 2003... - 450
Capital lease obligations .............................. 4,715 16
------- -------
Total non-utility 29,087 12,984
Less: current portion 6,813 2,960
------- -------
Net non-utility long-term debt $22,274 $10,024
======= =======
The fair value of the Company's long-term debt at December 31, 1995 and 1994 is
estimated to be $733.2 million, or 107% of the carrying value and $673.0
million, or 93% of the carrying value, respectively. These estimates are based
on available market information.
NOTE 8. BANK BORROWINGS AND COMMERCIAL PAPER
At December 31, 1995, the Company maintained total lines of credit with various
banks under two separate credit agreements amounting to $160,000,000. The
Company has one revolving line of credit, expiring December 9, 1997, which
provides a total credit commitment of $70,000,000. The second revolving credit
agreement is composed of two tranches totaling $90,000,000. One tranche
provides for up to $50,000,000 of notes to be outstanding at any one time, while
the other provides for up to $40,000,000 of notes to be outstanding at any one
time. Both tranches of this agreement expire on July 24, 1996. The Company
pays commitment fees of up to 0.15% per annum on the average daily unused
portion of each credit agreement.
In addition, under various agreements with banks, the Company can have up to
$60,000,000 in loans outstanding at any one time, with the loans available at
the banks' discretion. These arrangements provide, if funds are made available,
for fixed-term loans for up to 180 days at a fixed rate of interest. In
December 1994, the Company terminated its commercial paper program.
Balances and interest rates of bank borrowings under these arrangements were as
follows:
Years Ended December 31,
------------------------
1995 1994
---- ----
(Dollars in thousands)
BALANCE OUTSTANDING AT END OF PERIOD:
Fixed-term loans................................. $10,000 $33,000
Revolving credit agreement....................... 19,500 25,000
MAXIMUM BALANCE DURING PERIOD:
Fixed-term loans................................. $10,000 $52,000
Commercial paper................................. - 20,000
Revolving credit agreement....................... 28,500 32,000
AVERAGE DAILY BALANCE DURING PERIOD:
Fixed-term loans................................. $ 5,484 $29,373
Revolving credit agreement....................... 13,886 10,941
AVERAGE ANNUAL INTEREST RATE DURING PERIOD:
Fixed-term loans................................. 6.15% 4.64%
Revolving credit agreement....................... 6.11 4.49
AVERAGE ANNUAL INTEREST RATE AT END OF PERIOD:
Fixed-term loans................................. 6.06% 6.28%
Revolving credit agreement....................... 6.08 6.28
38
42
THE WASHINGTON WATER POWER COMPANY
================================================================================
Non-utility operations have $48 million in short-term borrowing arrangements
available. At December 31, 1995 and 1994, $26.6 million and $22.3 million,
respectively, were outstanding.
NOTE 9. LEASES
The Company has entered into several lease arrangements involving various
assets, with minimum terms ranging from eleven months to seventeen years and
expiration dates from 1995 to 2011. Certain of the lease arrangements require
the Company, upon the occurrence of specified events, to purchase the leased
assets for varying amounts over the term of the lease. The Company's management
believes that the likelihood of the occurrence of the specified events under
which the Company could be required to purchase the property is remote. Rent
expense for the years ended December 31, 1995, 1994 and 1993 was $10.7 million,
$2.3 million and $1.9 million, respectively. Future minimum lease payments (in
thousands of dollars) required under operating leases that have initial or
remaining noncancelable lease terms in excess of one year as of December 31,
1995 are estimated as follows:
Year ending December 31:
1996 $ 8,450
1997 7,635
1998 1,847
1999 2,257
2000 2,257
Later years 24,829
-------
Total minimum payments required $47,275
=======
The Company also has various other operating leases, which are charged to
operating expense, consisting of a large number of small, relatively short-term,
renewable agreements for various items, such as office equipment and office
space.
NOTE 10. PENSION PLANS
The Company has a pension plan covering substantially all of its regular
full-time employees. Certain of the Company's subsidiaries also participate in
this plan. Individual benefits under this plan are based upon years of service
and the employee's average compensation as specified in the Plan. The Company's
funding policy is to contribute annually an amount equal to the net periodic
pension cost, provided that such contributions are not less than the minimum
amounts required to be funded under the Employee Retirement Income Security Act,
nor more than the maximum amounts which are currently deductible for tax
purposes. Pension fund assets are invested primarily in marketable debt and
equity securities. The Company also has another Plan which covers the executive
officers.
Net pension cost (income) for 1995, 1994 and 1993 is summarized as follows:
1995 1994 1993
-------- -------- --------
(Thousands of Dollars)
Service cost-benefits earned during the period..... $ 3,464 $ 4,323 $ 3,150
Interest cost on projected benefit obligation...... 9,142 8,523 7,771
Actual return on plan assets....................... (27,910) (248) (15,108)
Net amortization and deferral...................... 17,272 (11,553) 3,717
-------- -------- --------
Net periodic pension cost (income)..... $ 1,968 $ 1,045 $ (470)
======== ======== ========
39
43
THE WASHINGTON WATER POWER COMPANY
================================================================================
The funded status of the Plans and the pension liability at December 31, 1995,
1994 and 1993, are as follows:
1995 1994 1993
--------- --------- ---------
(Thousands of dollars)
Actuarial present value of benefit obligation:
Accumulated benefit obligation (including vested benefits of
$(114,964,000), $(88,596,000) and $(84,531,000), respectively) $(116,877) $ (90,341) $ (85,368)
========= ========= =========
Projected benefit obligation for service rendered to date $(133,233) $(107,540) $(104,025)
Plan assets at fair value 140,528 119,706 126,879
--------- --------- ---------
Plan assets in excess of projected benefit obligation 7,295 12,166 22,854
Unrecognized net gain from returns different than assumed (19,704) (17,939) (21,503)
Prior service costs not yet recognized 18,385 14,803 7,983
Unrecognized net transition asset at year-end
(being amortized over 11 to 19 years) (10,273) (11,359) (12,445)
Regulatory deferrals - (1,841) (3,256)
--------- --------- ---------
Pension liability $ (4,297) $ (4,170) $ (6,367)
========= ========= =========
Assumptions used in calculations were:
Discount rate at year-end 7.5% 8.5% 7.5%
Rate of increase in future compensation level 4.0% 4.0% 4.0%
Expected long-term rate of return on assets 9.0% 9.0% 9.0%
NOTE 11. OTHER POSTRETIREMENT BENEFITS
FAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," requires the Company to accrue the estimated cost of postretirement
benefit payments during the years that employees provide services and allows
recognition of the unrecognized transition obligation in the year of adoption
or the amortization of such obligation over a period of up to twenty years. The
Company elected to amortize this obligation of approximately $34,500,000 over a
period of twenty years, beginning in 1993.
The Company has received accounting orders from the Washington Utilities and
Transportation Commission (WUTC) and the IPUC allowing the current deferral of
expense accruals under this Statement as a regulatory asset for future recovery.
At such time that rate recovery is requested and allowed, cumulative deferrals
will be amortized over the remainder of the twenty-year amortization period.
The Company expects to be able to recover the amortized amounts. Therefore, the
Company's cash flows and income from operations were not affected by
implementation of this Statement through 1995. The Company will begin
recognition of the expense accruals in 1996.
The Company provides certain health care and life insurance benefits for
substantially all of its retired employees. In 1995, 1994 and 1993, the Company
recognized $1,800,000, $1,270,000 and $1,250,000, respectively, as an expense
for postretirement health care and life insurance benefits. The following table
sets forth the health care plan's funded status at December 31, 1995, 1994 and
1993.
Accumulated postretirement benefit obligation (thousands of dollars):
1995 1994 1993
-------- -------- --------
Retirees 617 642 620
Active plan participants 1,328 1,319 1,341
-------- -------- --------
Total participants 1,945 1,961 1,961
Unfunded accumulated postretirement benefit obligation $(28,718) $(31,072) $(39,595)
Unrecognized (gain)/loss (3,396) (4,897) 1,886
Unrecognized transition obligation 27,288 28,894 33,600
-------- -------- --------
Accrued postretirement benefit cost $ (4,826) $ (7,075) $ (4,109)
======== ======== ========
40
44
THE WASHINGTON WATER POWER COMPANY
================================================================================
Net postretirement benefit cost for 1995, 1994 and 1993 (thousands of dollars):
1995 1994 1993
------ ------ ------
Service cost - benefits earned during the period $ 573 $ 802 $1,156
Return on the plan assets (if any) (226) - -
Interest cost on accumulated postretirement benefit obligation 2,452 2,596 3,006
Amortization of transition obligation 1,414 1,606 1,769
------ ------ ------
Total net periodic cost $4,213 $5,004 $5,931
====== ====== ======
The currently assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation is 8.0% for 1995, decreasing
linearly each successive year until it reaches 5.0% in 1999. The assumed rate
of future medical cost increases has been gradually decreased since the adoption
of FAS 106 in response to the actual leveling off of cost increases in the plan.
A one-percentage-point increase in the assumed health care cost trend rate for
each year would increase the accumulated postretirement benefit obligation as of
December 31, 1995 and net postretirement health care cost by approximately
$2,299,000. The assumed discount rate used in determining the accumulated
postretirement benefit obligation was 7.5%.
NOTE 12. ACCOUNTING FOR INCOME TAXES
As of December 31, 1995 and 1994, the Company had recorded net regulatory assets
of $169,432,000 and $174,349,000, respectively, related to the probable recovery
of FAS No. 109, "Accounting for Income Taxes," deferred tax liabilities from
customers through future rates. Such net regulatory assets will be adjusted by
amounts recovered through rates.
Deferred income taxes reflect the net tax effects of (a) temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes, and (b) tax credit
carryforwards. The net deferred federal income tax liability consists of the
following (thousands of dollars):
1995 1994 1993
-------- -------- --------
Deferred tax liabilities:
Differences between book and tax bases
of utility plant $320,502 $317,991 $297,175
Loss on reacquired debt 7,173 8,216 9,243
Deferred natural gas credits - 1,095 2,679
Other 10,013 8,957 5,575
-------- -------- --------
Total deferred tax liabilities 337,688 336,259 314,672
-------- -------- --------
Deferred tax assets:
Reserves not currently deductible 15,742 14,429 14,486
Contributions in aid of construction 4,634 3,710 2,975
Deferred natural gas credits 3,894 - -
Gain on sale of office building 1,463 1,555 1,647
Other 4,426 6,398 6,659
-------- -------- --------
Total deferred tax assets 30,159 26,092 25,767
-------- -------- --------
Net deferred tax liability $307,529 $310,167 $288,905
======== ======== ========
41
45
THE WASHINGTON WATER POWER COMPANY
================================================================================
A reconciliation of federal income taxes derived from statutory tax rates
applied to income from continuing operations and federal income tax as set forth
in the accompanying Consolidated Statements of Income and Retained Earnings is
as follows (the current and deferred effective tax rates are approximately the
same during all periods):
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
---- ---- ----
(Thousands of Dollars)
Computed federal income taxes at statutory rate.. $47,875 $41,983 $43,363
Increase (decrease) in tax resulting from:
Accelerated tax depreciation................... (909) 1,725 (2,229)
Equity earnings in affiliates.................. - (497) (560)
Other.......................................... 1,297 (1,320) 1,684
------- ------- -------
Total federal income tax expense*................ $48,263 $41,891 $42,258
======= ======= =======
INCOME TAX EXPENSE CONSISTS OF THE FOLLOWING:
Federal taxes currently provided................. $48,318 $32,334 $34,749
Deferred income taxes............................ (55) 9,557 7,509
------- ------- -------
Total federal income tax expense................. 48,263 41,891 42,258
State income tax expense....................... 4,153 2,805 245
------- ------- -------
Federal and state income taxes................... $52,416 $44,696 $42,503
======= ======= =======
*Federal Income Tax Expense:
Utility........................................ $41,203 $35,513 $36,385
Non-utility.................................... 7,060 6,378 5,873
------- ------- -------
Total Federal Income Tax Expense................. $48,263 $41,891 $42,258
======= ======= =======
Federal statutory rate........................... 35% 35% 35%
NOTE 13. LONG-TERM PURCHASED POWER CONTRACTS WITH REQUIRED MINIMUM PAYMENTS
Under fixed contracts with Public Utility Districts (PUD), the Company has
agreed to purchase portions of the output of certain generating facilities.
Although the Company has no investment in such facilities, these contracts
provide that the Company pay certain minimum amounts (which are based at least
in part on the debt service requirements of the supplier) whether or not the
facility is operating. The cost of power obtained under the contracts,
including payments made when a facility is not operating, is included in
operations and maintenance expense in the Consolidated Statements of Income.
Information as of December 31, 1995, pertaining to these contracts is summarized
in the following table:
COMPANY'S CURRENT SHARE OF
---------------------------------------------------------------
Contract
Debt Revenue Expira-
Kilowatt Annual Service Bonds tion
Output Capability Costs(2) Costs(3) Outstanding Date
------ ---------- -------- -------- ----------- ----
(Thousands of Dollars)
PUD Contracts:
Chelan County PUD:
Lake Chelan Project....... 100.0%(1) 58,000 $1,933 $ 258 $ - 1995
Rocky Reach Project....... 2.9 37,000 1,166 556 3,617 2011
Grant County PUD:
Priest Rapids Project..... 6.1 55,000 1,766 1,132 7,830 2005
Wanapum Project........... 8.2 75,000 2,194 1,460 15,009 2009
Douglas County PUD:
Wells Project............. 3.9 30,000 1,021 608 7,392 2018
------ ------ ------ -------
Totals.................. 255,000 $8,080 $4,014 $33,848
======= ====== ====== =======
42
46
THE WASHINGTON WATER POWER COMPANY
================================================================================
(1) The Company purchased 100% of the Lake Chelan Project output and sold back
to the PUD about 40% of the output to supply local service area
requirements. The contract expired during 1995.
(2) The annual costs will change in proportion to the percentage of output
allocated to the Company in a particular year. Amounts represent the
operating costs for the year 1995.
(3) Included in annual costs.
Actual expenses for payments made under the above contracts for the years 1995,
1994 and 1993, were $8,080,000, $8,717,000 and $8,721,000, respectively. The
estimated aggregate amounts of required minimum payments (the Company's share of
debt service costs) under the above contracts for the next five years are
$3,684,000 in 1996, $3,860,000 in 1997, $5,555,000 in 1998, $5,594,000 in 1999
and $6,948,000 in 2000 (minimum payments thereafter are dependent on then market
conditions). In addition, the Company will be required to pay its proportionate
share of the variable operating expenses of these projects.
NOTE 14. COMMITMENTS AND CONTINGENCIES
NEZ PERCE TRIBE
On December 6, 1991, the Nez Perce Tribe filed an action against the Company in
U. S. District Court for the District of Idaho alleging, among other things,
that two dams formerly operated by the Company, the Lewiston Dam on the
Clearwater River and the Grangeville Dam on the South Fork of the Clearwater
River, provided inadequate passage to migrating anadromous fish in violation of
rights under treaties between the Tribe and the United States made in 1855 and
1863. The Lewiston and Grangeville Dams, which had been owned and operated by
other utilities under hydroelectric licenses from the Federal Power Commission
(the "FPC", predecessor of the FERC) prior to acquisition by the Company, were
acquired by the Company in 1937 with the approval of the FPC, but were
dismantled and removed in 1973 and 1963, respectively. The Tribe initially
indicated through expert opinion disclosures that they were seeking actual and
punitive damages of $208 million. However, supplemental disclosures reflect
allegations of actual loss under different assumptions of between $425 million
and $650 million.
Discovery had been stayed pending a decision by the Court on a case involving
some similar issues brought by the Tribe against Idaho Power Company. The Court
has since decided these issues and has dismissed all claims against Idaho Power.
The Idaho Power case has now been appealed by the Nez Perce Tribe to the Ninth
Circuit Court of Appeals. On November 21, 1994, the Company filed its Motion
and Brief in Support of Summary Judgment of Dismissal. The Nez Perce Tribe has
filed a reply brief, and has requested oral argument. A hearing on the
Company's Motion for Summary Judgment was held by the Court on July 27, 1995.
On September 22, 1995, the federal magistrate issued a written opinion
recommending to the District Court that the Company's Motion for Summary
Judgment be granted and the Tribe's claims dismissed. The matter is still
pending before the District Court. The case has not yet been set for trial.
The Company is presently unable to assess the likelihood of an adverse outcome
in this litigation, or estimate an amount or range of potential loss in the
event of an adverse outcome.
OIL SPILL
The Company completed an updated investigation of an oil spill from an
underground storage tank that occurred several years ago in downtown Spokane at
the site of the Company's steam heat plant. The Company purchased the plant in
1916 and operated it as a non-regulated plant until it was deactivated in 1986
in a business decision unrelated to the spill. After the Bunker C fuel oil
spill, initial studies suggested that the oil was being adequately contained by
both geological features and man-made structures. The Washington State
Department of Ecology (DOE) concurred with these findings. However, more recent
tests showed that the oil has migrated approximately one city block beyond the
steam plant property. On December 6, 1993, the Company asked the DOE to enter
into negotiations for a Consent Decree which provided for additional remedial
investigation and a feasibility study. The Consent Decree, entered on November
8, 1994, provided for 22 additional soil borings to be made around the site,
which have been completed. It is anticipated that a clean-up action plan will
be approved by the first quarter of 1996 and that the oil spill clean-up will be
conducted in 1996. As of December 31, 1995, an accrual of $3.1 million is
reflected on the Company's financial statements, which represents the Company's
best estimate of its liability.
The Company has completed a remedial investigation/feasibility study (RI/FS)
report, which has been submitted to the DOE. The RI/FS report is subject to
public review and comment. The report includes a recommended clean-up action
plan (RCAP).
43
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THE WASHINGTON WATER POWER COMPANY
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On August 17, 1995, a lawsuit was filed against the Company in Superior Court of
the State of Washington for Spokane County by Davenport Sun International Hotels
and Properties, Inc., the owner of a hotel property in downtown Spokane,
Washington. The Complaint alleges that the oil released from the Company's
Central Steamplant trespassed on property owned by the plaintiff. In addition,
the plaintiff claims that the Steamplant has caused a diminution of value of
plaintiff's land. Generally, the Complaint is based on a claim of negligence,
trespass and nuisance. Discovery has been initiated by the Company and is in
the initial stages. The matter has not been set for trial. The Company is
presently unable to assess the likelihood of an adverse outcome in this
litigation, or estimate an amount or range of potential loss in the event of an
adverse outcome.
FIRESTORM
On October 16, 1991, gale-force winds struck a five-county area in eastern
Washington and a seven-county area in northern Idaho. These winds were
responsible for causing 92 separate wildland fires, resulting in two deaths and
the loss of 114 homes and other structures, some of which were located in the
Company's service territory. Four separate class action lawsuits were filed
against the Company by private individuals in the Superior Court of Spokane
County on October 13, 1993. These suits concern fires identified as Midway,
Golden Cirrus, Nine Mile and Chattaroy. All of these suits were certified as
class actions on September 16, 1994, and bifurcated for trial of liability and
damage issues by order of the same date. The Company's Motion for
Reconsideration was denied on October 21, 1994, and a Motion for Discretionary
Review of the Court's decision on certification of class actions was timely
filed with the Washington Court of Appeals (Division III) on November 14, 1994.
The Company was also served with two suits in Spokane County Superior Court
filed on April 20, 1994 and on September 15, 1994, both of which sought
individual damages from separate fires within the Chattaroy Fire complex. Five
additional and separate suits were brought by Grange Insurance Company, and were
filed in Spokane County Superior Court on October 10, 1994, for approximately
$2.2 million paid to Grange insureds for the same fire areas. Two additional
class action suits were also filed - one in Lincoln County Superior Court, filed
on October 14, 1994, for a fire known as "Nine Mile West" (previously included
in the Spokane County Nine Mile suit certified as a class action), and the
second in Spokane County Superior Court, filed on October 14, 1994, for the
Ponderosa Fire area (which had not been the subject of previous suit). The
Lincoln County suit has been transferred to Spokane County and both suits have
now also been certified as class actions.
Complainants in all cases allege various theories of tortious conduct, including
negligence, creation of a public nuisance, strict liability and trespass; in
most cases, complainants allege that fires were caused by electric distribution
and/or transmission lines downed by wind-downed trees. The lawsuits seek
recovery for property damage, emotional and mental distress, lost income and
punitive damages, but do not specify the amount of damages being sought.
Discovery is ongoing and the Company is presently unable to assess the
likelihood of an adverse outcome or estimate an amount or range of potential
loss in the event of an adverse outcome. Trials are scheduled to commence on
various dates between February 3, 1997 and November 2, 1998. The Company was
previously presented with a claim from the Washington State Department of
Natural Resources (DNR) for fire suppression costs associated with five of these
fires in eastern Washington. The total of the DNR claim was $1.0 million. On
July 22, 1993, the Company entered into a settlement with the DNR whereby the
Company agreed to pay $200,000 to DNR in full settlement of any and all DNR
claims; however, there was no admission of liability on the part of the Company.
WILLIAMS LAKE LAWSUIT
On December 21, 1995, a lawsuit was commenced in Vancouver, British Columbia
against the Company's subsidiary, Pentzer Corporation (Pentzer), by Tondu Energy
Systems, Inc. and T.E.S. Williams Lake Partnership alleging contract violations,
conspiracy, misrepresentation and breach of fiduciary duties in regard to the
1993 sale of assets of Pentzer Energy Services, Inc. to B.C. Gas, Inc. and a
U.S. subsidiary of B.C. Gas. The claims involve an alleged first right to
purchase interests in the Williams Lake, British Columbia wood-fired generating
station. The suit seeks damages in excess of $10 million, plus exemplary
damages, prejudgment interest, costs and attorneys' fees. Also named as
defendants are B.C. Gas, Inc., Inland Pacific Energy (Williams Lake) Corp.,
Pentzer Energy Services, Inc. and WP Energy Company. This action originally had
been filed in Spokane Superior Court against each of the same defendants and
Washington Water Power. By order dated June 6, 1995, all claims against
Washington Water Power were dismissed by that court with prejudice and the
claims against the remaining defendants were dismissed without prejudice on the
grounds that the lawsuit should have been brought in British Columbia. The
Company is presently unable to assess the likelihood of an adverse outcome or
estimate an amount or range of potential loss in the event of an adverse
outcome.
44
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THE WASHINGTON WATER POWER COMPANY
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OTHER CONTINGENCIES
The Company routinely assesses, based on in-depth studies, expert analyses and
legal reviews, its contingencies, obligations and commitments for remediation of
contaminated sites, including assessments of ranges and probabilities of
recoveries from other responsible parties who have and have not agreed to a
settlement and recoveries from insurance carriers. The Company's policy is to
immediately accrue and charge to current expense identified exposures related to
environmental remediation sites based on estimates of investigation, cleanup and
monitoring costs to be incurred.
The Company has long-term contracts related to the purchase of fuel for thermal
generation, natural gas and hydroelectric power. Terms of the natural gas
purchase contracts range from one month to five years and the majority provide
for minimum purchases at the then effective market rate. The Company also has
various agreements for the purchase, sale or exchange of electric energy with
other utilities, cogenerators, small power producers and government agencies.
As of December 31, 1995, the Company's collective bargaining agreement with the
International Brotherhood of Electrical Workers represented approximately 47% of
employees. The current agreement with the union local representing the majority
of the bargaining unit employees expires on March 25, 1997. A local agreement
in the South Lake Tahoe area, which represents approximately 7 employees,
expires on June 30, 1996.
NOTE 15. ACQUISITIONS AND DISPOSITIONS
During 1995, Pentzer acquired two companies, one that designs and packages
point-of-purchase displays and other marketing materials for national
manufacturers of consumer products and the other that manufactures and assembles
metal and wood products for the computer, video arcade and point-of-purchase
industries. In 1994 and 1993, Pentzer acquired two and three companies,
respectively. Sales of Pentzer's interest in companies involved in
telecommunications, technology and energy services resulted in transactional
gains of $7.1 million in 1993.
In 1992, Pentzer's common stock ownership in ITRON was reduced from
approximately 60% to approximately 40% as a result of the issuance of common
stock by ITRON in an acquisition. Accordingly, beginning in 1992, Pentzer's
share of ITRON's earnings was accounted for by the equity method and was
included in Other Income-Net and its investment in ITRON was reflected on the
balance sheet under Other Property and Investments. ITRON's initial public
offering in November 1993 and Pentzer's sales of ITRON stock during 1993 and
1994 resulted in a reduction in Pentzer's ownership interest to approximately
14%. As a result, Pentzer's investment in ITRON, beginning in December 1994,
is classified as available for sale and recorded at fair value on the
Consolidated Balance Sheets.
On March 1, 1996, a subsidiary of Pentzer sold certain property that was held
for sale. The sale resulted in a pre-tax gain of approximately $19.3 million,
which will be recognized in the first quarter of 1996.
NOTE 16. PROPOSED MERGER
In June 1994, the Company, Sierra Pacific Resources (SPR), Sierra Pacific Power
Company, a subsidiary of SPR (SPPC), and Altus Corporation, a newly formed
subsidiary of the Company (Altus, formerly named Resources West Energy
Corporation), entered into an Agreement and Plan of Reorganization and Merger,
dated as of June 27, 1994, as amended October 4, 1994 which provides for the
merger of the Company, SPR and SPPC with and into Altus. In 1994, applications
seeking approval of the merger were filed with the Federal Energy Regulatory
Commission (FERC) and with the state utility commissions of California, Idaho,
Montana, Nevada, Oregon and Washington. The Montana Public Service Commission
issued an order in October 1994 declining to exercise jurisdiction. The Company
has received orders approving the merger from the commissions of all the other
states. On November 29, 1995, the FERC ordered evidentiary hearings concerning
the proposed merger. An administrative law judge has been assigned to the
merger proceeding and a pre-hearing conference was held on December 13, 1995 to
set a procedural schedule. The companies filed supplemental testimony on
February 1, 1996. Hearings are scheduled to begin on June 4, 1996. Based on
this schedule, the companies believe an order could be issued by the FERC in
1996 or early 1997.
45
49
THE WASHINGTON WATER POWER COMPANY
================================================================================
The merger is designed to qualify as a pooling-of-interests for accounting and
financial reporting purposes. Under this method of accounting, the recorded
assets and liabilities of the Company, SPR and SPPC will be carried forward to
the consolidated financial statements of Altus at their recorded amounts; income
of Altus will include income of the Company, SPR and SPPC for the entire fiscal
year in which the merger occurs; and the reported income of the separate
corporations for prior periods will be combined and restated as income of Altus.
As of December 31, 1995, $14.5 million in merger transaction and transition
costs have been deferred and are included on the Company's balance sheet as
Other Deferred Charges. The cost of severance and early retirement options
elected by certain eligible employees affected by the merger is expected to be
approximately $8 million. The Company will determine the treatment of these
costs based on regulatory rulings, generally accepted accounting principles and
tax regulations. It is anticipated that for accounting purposes these merger
transaction and transition costs will be expensed by Altus in the quarter the
merger is completed.
The following pro forma condensed financial information combines the historical
consolidated balance sheets and statements of income of the Company and SPR
after giving effect to the merger. The unaudited pro forma condensed
consolidated balance sheet at December 31, 1995 gives effect to the merger as if
it had occurred at December 31, 1995. The unaudited pro forma condensed
consolidated statements of income for each of the three years in the period
ended December 31, 1995 give effect to the merger as if it had occurred at
January 1, 1993. These statements are prepared on the basis of accounting for
the merger as a pooling-of-interests and are based on the assumptions set forth
in the paragraph below. The pro forma condensed financial information has been
prepared from, and should be read in conjunction with the Company's historical
consolidated audited financial statements and related notes thereto of which
this note is a part and SPR's historical consolidated audited financial
statements and related notes thereto included in reports filed by SPR pursuant
to the Securities Exchange Act, as amended. The information contained herein
with respect to SPR and its subsidiaries has been supplied by SPR. The
information is not necessarily indicative of the financial position or operating
results that would have occurred had the merger been consummated on the date, or
at the beginning of the periods, for which the merger is being given effect, nor
is it necessarily indicative of future operating results or financial position.
Intercompany transactions (including purchased and exchanged power transactions)
between the Company and SPR during the periods presented were not material and,
accordingly, no pro forma adjustments were made to eliminate such transactions.
For comparative purposes, certain historical amounts have been reclassified to
conform to the pro forma condensed financial statement format. The net cost
savings estimated to be achieved by the merger are not reflected in the pro
forma financial statements. Pro forma per share data and common shares
outstanding for Altus give effect to the conversion of each share of WWP Common
Stock into one share of Altus Common Stock and the conversion of each share of
SPR Common Stock into 1.44 shares of Altus Common Stock.
46
50
THE WASHINGTON WATER POWER COMPANY
================================================================================
Pro Forma Condensed Consolidated Balance Sheet (unaudited, in thousands of
dollars):
At December 31, 1995
WWP SPR ALTUS
---------- ---------- ----------
Assets
Utility plant in service-net................ $1,880,620 $1,816,444 $3,697,064
Construction work in progress............... 23,046 153,066 176,112
---------- ---------- ----------
Total.................................... 1,903,666 1,969,510 3,873,176
Accumulated depreciation and amortization... 546,248 556,710 1,102,958
---------- ---------- ----------
Net utility plant........................ 1,357,418 1,412,800 2,770,218
Other property and investments.............. 227,457 45,290 272,747
Current assets.............................. 183,972 129,414 313,386
Deferred charges............................ 330,055 169,123 499,178
---------- ---------- ----------
Total assets............................. $2,098,902 $1,756,627 $3,855,529
========== ========== ==========
Capitalization and Liabilities
Common stock and additional paid-in
capital.................................. $ 594,636 $ 463,705 $1,058,341
Other shareholders equity................... 122,489 80,845 203,334
Preferred stock............................. 135,000 86,715 221,715
Long-term debt.............................. 738,287 573,933 1,312,220
---------- ---------- ----------
Total capitalization..................... 1,590,412 1,205,198 2,795,610
Current liabilities......................... 168,959 203,364 372,323
Deferred income taxes....................... 309,790 159,300 469,090
Other deferred credits...................... 29,741 188,765 218,506
---------- ---------- ----------
Total capitalization and liabilities..... $2,098,902 $1,756,627 $3,855,529
========== ========== ==========
Common shares outstanding (thousands)....... 55,948 30,035 99,198
Pro Forma Condensed Consolidated Statements of Income (unaudited, in thousands
of dollars, except per share amounts):
1995 WWP SPR ALTUS
- ---- -------- -------- ----------
Operating revenues.......................... $755,009 $606,122 $1,361,131
Operating expenses.......................... 565,169 464,787 1,029,956
Income from operations...................... 189,840 141,335 331,175
Net income.................................. 87,121 65,413 152,534
Income available for common stock........... 77,998 58,039 136,037
Average common shares outstanding........... 55,173 29,755 98,020
Earnings per share.......................... $ 1.41 $ 1.95 $ 1.39
47
51
THE WASHINGTON WATER POWER COMPANY
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1994 WWP SPR ALTUS
- ---- -------- -------- ----------
Operating revenues.......................... $670,765 $626,312 $1,297,077
Operating expenses.......................... 515,307 498,860 1,014,167
Income from operations...................... 155,458 127,452 282,910
Net income.................................. 77,197 60,300 137,497
Income available for common stock........... 68,541 52,366 120,907
Average common shares outstanding........... 53,538 29,219 95,613
Earnings per share.......................... $ 1.28 $ 1.79 $ 1.26
1993 WWP SPR ALTUS
- ---- -------- -------- ----------
Operating revenues.......................... $640,599 $528,075 $1,168,674
Operating expenses.......................... 479,749 415,286 895,035
Income from operations...................... 160,850 112,789 273,639
Net income.................................. 82,776 53,151 135,927
Income available for common stock........... 74,441 44,890 119,331
Average common shares outstanding........... 51,616 26,895 90,345
Earnings per share.......................... $ 1.44 $ 1.67 $ 1.32
48
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THE WASHINGTON WATER POWER COMPANY
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NOTE 17. SELECTED QUARTERLY INFORMATION (UNAUDITED)
The Company's electric and natural gas operations are significantly affected by
weather conditions. Consequently, there can be large variances in revenues,
expenses and net income between quarters based on seasonal factors such as
temperatures and streamflow conditions.
A summary of quarterly operations (in thousands of dollars except per share
amounts) for 1995 and 1994 follows:
Three Months Ended
------------------------------------------
March June September December
31 30 30 31
-------- -------- -------- --------
1995
Operating revenues................. $197,928 $158,973 $157,869 $240,239
Operating income................... 58,474 40,103 31,565 59,698
Net income......................... 28,453 15,163 10,885 32,619
Income available for common stock.. 26,156 12,865 8,618 30,359
Outstanding common stock (000s):
Weighted average................. 54,582 54,986 55,363 55,745
Year-end......................... 54,847 55,237 55,617 55,948
Earnings per share:
Utility operations............... $ 0.43 $ 0.19 $ 0.11 $ 0.41
Non-utility operations........... 0.05 0.04 0.05 0.13
-------- -------- -------- --------
Total............................ $ 0.48 $ 0.23 $ 0.16 $ 0.54
Dividends paid per common share.... $ 0.31 $ 0.31 $ 0.31 $ 0.31
Trading price range per share:
High............................. $ 16 $ 16 $ 16 3/8 $ 18
Low.............................. $ 13 1/2 $ 14 3/4 $ 15 $ 16
1994
Operating revenues................. $190,871 $147,173 $142,334 $190,552
Operating income................... 51,690 34,015 22,973 46,782
Net income......................... 26,691 15,696 8,104 26,705
Income available for common stock.. 24,621 13,547 5,918 24,455
Outstanding common stock (000s):
Weighted average................. 52,911 53,316 53,751 54,158
Year-end......................... 53,140 53,584 54,017 54,421
Earnings per share:
Utility operations............... $ 0.43 $ 0.21 $ 0.05 $ 0.34
Non-utility operations........... 0.03 0.04 0.06 0.12
-------- -------- -------- --------
Total............................ $ 0.46 $ 0.25 $ 0.11 $ 0.46
Dividends paid per common share.... $ 0.31 $ 0.31 $ 0.31 $ 0.31
Trading price range per share:
High............................. $ 18 7/8 $ 17 7/8 $ 16 1/4 $ 14 7/8
Low.............................. $ 16 5/8 $ 14 1/4 $ 13 7/8 $ 13 5/8
49
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THE WASHINGTON WATER POWER COMPANY
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of the Registrant has been omitted pursuant
to General Instruction G to Form 10-K. Reference is made to the Registrant's
Proxy Statement to be filed with the Securities and Exchange Commission in
connection with the Registrant's annual meeting of shareholders to be held on
May 13, 1996.
Executive Officers of the Registrant
Name Age Business Experience During Past 5 Years
- ---- --- ---------------------------------------
Paul A. Redmond 59 Chairman of the Board, President and Chief Executive
Officer since February 1994; Chairman of the Board and
Chief Executive Officer May 1988 - February 1994.
W. Lester Bryan 55 Senior Vice President - Rates & Resources since May
1992; Vice President - Power Supply August 1983 - May
1992.
Jon E. Eliassen 48 Vice President - Finance and Chief Financial Officer
since February 1986.
Gary G. Ely 48 Vice President - Natural Gas since February 1991.
Robert D. Fukai 46 Vice President - Human Resources, Corporate Services &
Marketing since January 1993; Vice President -
Corporate Services & Human Resources October 1992 -
December 1992; Vice President - Operations May 1986 -
October 1992.
JoAnn G. Matthiesen 55 Vice President - Organization Effectiveness, Public
Relations & Assistant to the Chairman since January
1993; Vice President - Marketing, Public Relations &
Assistant to the Chairman February 1991 - January
1993.
Lawrence J. Pierce 43 Vice President - Business Analysis since August 1994;
Director - Business Analysis February 1992 - August
1994; Treasurer February 1986 - February 1992.
Nancy J. Racicot 48 Vice President - Operations since October 1992; Vice
President - Corporate Services March 1990 - October
1992.
Ronald R. Peterson 43 Treasurer since February 1992; Manager - Customer
Information Services March 1991 - February 1992.
John W. Buergel 52 Controller since May 1990.
Terry L. Syms 47 Corporate Secretary & Manager - Shareholder Relations
since March 1988.
All of the Company's executive officers, with the exception of Messrs. Bryan,
Ely, and Buergel and Ms. Racicot, were officers or directors of one or more of
the Company's subsidiaries in 1995.
Executive officers are elected annually by the Board of Directors.
50
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THE WASHINGTON WATER POWER COMPANY
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ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation has been omitted pursuant to
General Instruction G to Form 10-K. Reference is made to the Registrant's Proxy
Statement to be filed with the Securities and Exchange Commission in connection
with the Registrant's annual meeting of shareholders to be held on May 13,
1996.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security ownership of certain beneficial owners (owning 5% or more of
Registrant's voting securities):
None.
(b) Security ownership of management:
Information regarding security ownership of management has been omitted
pursuant to General Instruction G to Form 10-K. Reference is made to the
Registrant's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Registrant's annual meeting of
shareholders to be held on May 13, 1996.
(c) Changes in control:
None.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions has been
omitted pursuant to General Instruction G to Form 10-K. Reference is made to
the Registrant's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Registrant's annual meeting of shareholders to
be held on May 13, 1996.
51
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THE WASHINGTON WATER POWER COMPANY
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PART IV
ITEM 14. FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND
REPORTS ON FORM 8-K
(a) 1. Financial Statements (Included in Part II of this report):
Independent Auditors' Report
Consolidated Statements of Income and Retained Earnings for the
Years Ended December 31, 1995, 1994 and 1993
Consolidated Balance Sheets, December 31, 1995 and 1994
Consolidated Statements of Capitalization, December 31, 1995 and
1994
Consolidated Statements of Cash Flows for the Years Ended December
31, 1995, 1994 and 1993
Schedule of Information by Business Segments for the Years Ended
December 31, 1995, 1994 and 1993
Notes to Financial Statements
(a) 2. Financial Statement Schedules:
None
(a) 3. Exhibits:
Reference is made to the Exhibit Index commencing on page 55. The
Exhibits include the management contracts and compensatory plans or
arrangements required to be filed as exhibits to this Form 10-K by
Item 601(10)(iii) of Regulation S-K.
(b) Reports on Form 8-K:
Dated November 29, 1995, regarding the FERC hearing process on the
proposed Merger between the Company, Sierra Pacific Resources
and Sierra Pacific Power Company.
52
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THE WASHINGTON WATER POWER COMPANY
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SIGNATURES
Pursuant to the requirements of Section 13 or 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.
THE WASHINGTON WATER POWER COMPANY
March 12, 1996 By /s/ PAUL A. REDMOND
- -------------- ------------------------------------------------------------
Date Paul A. Redmond
Chairman of the Board, President and Chief Executive Officer
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 and on the dates indicated.
Signature Title Date
--------- ----- ----
Principal Executive
/s/ PAUL A. REDMOND Officer and Director March 12, 1996
- ----------------------------------------
Paul A. Redmond (Chairman of the Board,
President and Chief Executive Officer)
Principal Financial
/s/ J. E. ELIASSEN and Accounting Officer March 12, 1996
- ----------------------------------------
J. E. Eliassen (Vice President - Finance
and Chief Financial Officer)
/s/ DAVID A. CLACK Director March 12, 1996
- ----------------------------------------
David A. Clack
/s/ DUANE B. HAGADONE Director March 12, 1996
- ----------------------------------------
Duane B. Hagadone
/s/ ROBERT S. JEPSON, JR. Director March 12, 1996
- ----------------------------------------
Robert S. Jepson, Jr.
/s/ EUGENE W. MEYER Director March 12, 1996
- ----------------------------------------
Eugene W. Meyer
/s/ H. NORMAN SCHWARZKOPF Director March 12, 1996
- ----------------------------------------
General H. Norman Schwarzkopf
/s/ B. JEAN SILVER Director March 12, 1996
- ----------------------------------------
B. Jean Silver
/s/ LARRY A. STANLEY Director March 12, 1996
- ----------------------------------------
Larry A. Stanley
/s/ R. JOHN TAYLOR Director March 12, 1996
- ----------------------------------------
R. John Taylor
53
57
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
2-81697 on Form S-8, in Registration Statement No. 2-94816 on Form S-8, in
Registration Statement No. 33-49662 on Form S-3, in Registration Statement No.
33-51669 on Form S-3, in Registration Statement No. 33-53655 on Form S-3 and in
Registration Statement No. 33-54791 on Form S-8 of our report dated January 26,
1996 (March 1, 1996 as to Note 15) appearing in this Annual Report on Form 10-K
of The Washington Water Power Company for the year ended December 31, 1995.
Deloitte & Touche LLP
Seattle, Washington
March 12, 1996
54
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THE WASHINGTON WATER POWER COMPANY
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EXHIBIT INDEX
Previously Filed*
-----------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------
2 1-3701 (with Form 8-K 2(a) Agreement and Plan of Reorganization and Merger, dated
dated June 27, 1994) as of June 27, 1994, by and among the Company, Sierra
Pacific Resources, Sierra Pacific Power Company, and
Resources West Energy Corporation.
3(a) 1-3701 (with 1994 4(a) Restated Articles of Incorporation of the Company as
2nd Quarter 10-Q) filed August 4, 1994.
3(b) 1-3701 (with 1995 4(a) Bylaws of the Company, as amended, May 11, 1995.
2nd Quarter 10-Q)
4(a)-1 2-4077 B-3 Mortgage and Deed of Trust, dated as of June 1, 1939.
4(a)-2 2-9812 4(c) First Supplemental Indenture, dated as of October 1, 1952.
4(a)-3 2-60728 2(b)-2 Second Supplemental Indenture, dated as of May 1, 1953.
4(a)-4 2-13421 4(b)-3 Third Supplemental Indenture, dated as of December 1, 1955.
4(a)-5 2-13421 4(b)-4 Fourth Supplemental Indenture, dated as of March 15, 1967.
4(a)-6 2-60728 2(b)-5 Fifth Supplemental Indenture, dated as of July 1, 1957.
4(a)-7 2-60728 2(b)-6 Sixth Supplemental Indenture, dated as of January 1, 1958.
4(a)-8 2-60728 2(b)-7 Seventh Supplemental Indenture, dated as of August 1, 1958.
4(a)-9 2-60728 2(b)-8 Eighth Supplemental Indenture, dated as of January 1, 1959.
4(a)-10 2-60728 2(b)-9 Ninth Supplemental Indenture, dated as of January 1, 1960.
4(a)-11 2-60728 2(b)-10 Tenth Supplemental Indenture, dated as of April 1, 1964.
4(a)-12 2-60728 2(b)-11 Eleventh Supplemental Indenture, dated as of March 1, 1965.
4(a)-13 2-60728 2(b)-12 Twelfth Supplemental Indenture, dated as of May 1, 1966.
4(a)-14 2-60728 2(b)-13 Thirteenth Supplemental Indenture, dated as of August 1, 1966.
4(a)-15 2-60728 2(b)-14 Fourteenth Supplemental Indenture, dated as of April 1, 1970.
4(a)-16 2-60728 2(b)-15 Fifteenth Supplemental Indenture, dated as of May 1, 1973.
4(a)-17 2-60728 2(b)-16 Sixteenth Supplemental Indenture, dated as of February 1, 1975.
4(a)-18 2-60728 2(b)-17 Seventeenth Supplemental Indenture, dated as of
November 1, 1976.
4(a)-19 2-69080 2(b)-18 Eighteenth Supplemental Indenture, dated as of June 1, 1980.
- -------------------
*Incorporated herein by reference.
**Filed herewith.
55
59
THE WASHINGTON WATER POWER COMPANY
================================================================================
EXHIBIT INDEX (continued)
Previously Filed*
-----------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------
4(a)-20 1-3701 (with 4(a)-20 Nineteenth Supplemental Indenture, dated as of January 1, 1981.
1980 Form 10-K)
4(a)-21 2-79571 4(a)-21 Twentieth Supplemental Indenture, dated as of August 1, 1982.
4(a)-22 1-3701 (with 4(a)-22 Twenty-First Supplemental Indenture, dated as of
Form 8-K dated September 1, 1983.
September 20, 1983)
4(a)-23 2-94816 4(a)-23 Twenty-Second Supplemental Indenture, dated as of
March 1, 1984.
4(a)-24 1-3701 (with 4(a)-24 Twenty-Third Supplemental Indenture, dated as of
1986 Form 10-K) December 1, 1986.
4(a)-25 1-3701 (with 4(a)-25 Twenty-Fourth Supplemental Indenture, dated as of
1987 Form 10-K) January 1, 1988.
4(a)-26 1-3701 (with 4(a)-26 Twenty-Fifth Supplemental Indenture, dated as of
1989 Form 10-K) October 1, 1989.
4(a)-27 33-51669 4(a)-27 Twenty-Sixth Supplemental Indenture, dated as of
April 1, 1993.
4(a)-28 1-3701 (with 4(a)-28 Twenty-Seventh Supplemental Indenture, dated as of
1993 Form 10-K) January 1, 1994.
4(b)-1 1-3701 (with 4(e)-1 Loan Agreement between City of Forsyth, Rosebud County,
1989 Form 10-K) and the Company, dated as of November 1, 1989 (Series
1989 A and 1989 B). Replaces Exhibit 4(e)-1 (agreement
between the Company and City of Forsyth, Rosebud County,
Montana, dated as of October 1, 1986) filed with Form 10-K
for 1986 and Exhibit 4(g)-1 (agreement between the Company
and City of Forsyth, Rosebud County, Montana, dated as of
April 1, 1987) filed with Form 10-K for 1987.
4(b)-2 1-3701 (with 4(e)-2 Indenture of Trust, Pollution Control Revenue Refunding
1989 Form 10-K) Bonds (Series 1989 A and 1989 B) between City of Forsyth,
Rosebud County, Montana and Chemical Bank, dated as of
November 1, 1989. Replaces Exhibit 4(e)-2 (Indenture
of Trust between City of Forsyth, Rosebud County, Montana
and Chemical Bank dated as of October 1, 1986) filed with
Form 10-K for 1986 and Exhibit 4(g)-2 (Indenture of Trust
between City of Forsyth, Rosebud County, Montana and
Chemical Bank, dated as of April 1, 1987) filed with Form
10-K for 1987.
4(c)-1 1-3701 (with 4(h)-1 Indenture between the Company and Chemical Bank dated
1988 Form 10-K) as of July 1, 1988 (Series A and B Medium-Term Notes).
- -------------------
*Incorporated herein by reference.
**Filed herewith.
56
60
THE WASHINGTON WATER POWER COMPANY
================================================================================
EXHIBIT INDEX (continued)
Previously Filed*
-----------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------
4(d)-1 1-3701 (with 4(j)-1 Credit Agreements between the Company and Toronto-
1992 Form 10-K) Dominion (Texas), Inc., The Toronto-Dominion Bank
Houston Agency, The Bank of New York, CIBC, Inc. and
Citicorp USA, Inc. with Toronto-Dominion (Texas), Inc.
as agent, dated as of October 1, 1992.
4(d)-2 ** First Amendment to Credit Agreements between the Company
and Toronto-Dominion (Texas), Inc., The Toronto-
Dominion Bank Houston Agency, The Bank of New York,
CIBC, Inc. and Citicorp USA, Inc. with Toronto-
Dominion (Texas), Inc. as agent, dated as of July 26, 1995.
4(d)-3 ** Second Amendment to Credit Agreements between the Company
and Toronto-Dominion (Texas), Inc., The Toronto-
Dominion Bank Houston Agency, The Bank of New York,
CIBC, Inc. and Citicorp USA, Inc. with Toronto-
Dominion (Texas), Inc. as agent, dated as of July 26, 1995.
4(e)-1 1-3701 (with 4(k)-1 Credit Agreements between the Company and Seattle-First
1992 Form 10-K) National Bank, West One Bank Idaho, N.A., First
Interstate Bank of Washington, N.A., First Security Bank
of Idaho, N.A., U.S. Bank of Washington, N.A., and
Washington Trust Bank with Seattle-First National Bank as
agent, dated as of December 10, 1992.
4(e)-2 ** Third Amendment to Credit Agreements between the Company
and Seattle-First National Bank, West One Bank Idaho, N.A.,
First Interstate Bank of Washington, N.A., First Security Bank
of Idaho, N.A., U.S. Bank of Washington, N.A., and
Washington Trust Bank with Seattle-First National Bank as
agent, dated as of November 21, 1994.
4(f)-1 1-3701 (with Form 8-K 4(n) Rights Agreement, dated as of February 16, 1990, between
dated February 16, 1990) the Company and the Bank of New York as successor
Rights Agent.
4(f)-2 1-3701 (with 1994 First 4(b) Amendment No. 1 to Rights Agreement, dated as of
Quarter Form 10-Q) May 10, 1994.
4(f)-3 1-3701 (with 1994 Third 4(b) Amendment No. 2 to Rights Agreement, dated as of
Quarter Form 10-Q) June 27, 1994.
10(a)-1 2-13788 13(e) Power Sales Contract (Rocky Reach Project) with
Public Utility District No. 1 of Chelan County,
Washington, dated as of November 14, 1957.
10(a)-2 2-60728 10(b)-1 Amendment to Power Sales Contract (Rocky Reach
Project) with Public Utility District No. 1 of Chelan
County, Washington, dated as of June 1, 1968.
- -------------------
*Incorporated herein by reference.
**Filed herewith.
57
61
THE WASHINGTON WATER POWER COMPANY
================================================================================
EXHIBIT INDEX (continued)
Previously Filed*
-----------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------
10(b)-1 2-13421 13(d) Power Sales Contract (Priest Rapids Project) with
Public Utility District No. 2 of Grant County,
Washington, dated as of May 22, 1956.
10(b)-2 2-60728 5(d)-1 Second Amendment to Power Sales Contract (Priest Rapids
Project) with Public Utility District No. 2 of Grant
County, Washington, dated as of December 19, 1977.
10(c)-1 2-60728 5(e) Power Sales Contract (Wanapum Project) with
Public Utility District No. 2 of Grant County,
Washington, dated as of June 22, 1959.
10(c)-2 2-60728 5(e)-1 First Amendment to Power Sales Contract (Wanapum
Project) with Public Utility District No. 2 of Grant
County, Washington, dated as of December 19, 1977.
10(d)-1 2-60728 5(g) Power Sales Contract (Wells Project) with Public Utility
District No. 1 of Douglas County, Washington, dated as
of September 18, 1963.
10(d)-2 2-60728 5(g)-1 Amendment to Power Sales Contract (Wells Project)
with Public Utility District No. 1 of Douglas County,
Washington, dated as of February 9, 1965.
10(d)-3 2-60728 5(h) Reserved Share Power Sales Contract (Wells Project)
with Public Utility District No. 1 of Douglas County,
Washington, dated as of September 18, 1963.
10(d)-4 2-60728 5(h)-1 Amendment to Reserved Share Power Sales Contract
(Wells Project) with Public Utility District No. 1 of Douglas
County, Washington, dated as of February 9, 1965.
10(e) 2-60728 5(i) Canadian Entitlement Exchange Agreement executed by
Bonneville Power Administration Columbia Storage Power
Exchange and the Company, dated as of August 13, 1964.
10(f) 2-60728 5(j) Pacific Northwest Coordination Agreement, dated as of
September 15, 1964.
10(g)-1 2-60728 5(k) Ownership Agreement between the Company, Pacific
Power & Light Company, Puget Sound Power & Light
Company, Portland General Electric Company, Seattle City
Light, Tacoma City Light and Grays Harbor and Snohomish
County Public Utility Districts as owners of the Centralia
Steam Electric Generating Plant, dated as of May 15, 1969.
- -------------------
*Incorporated herein by reference.
**Filed herewith.
58
62
THE WASHINGTON WATER POWER COMPANY
================================================================================
EXHIBIT INDEX (continued)
Previously Filed*
-----------------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------
10(g)-3 1-3701 (with Form 10(h)-3 Centralia Fuel Supply Agreement between PacifiCorp
10-K for 1991) Electric Operations, as the Seller, and the Company, Puget
Sound Power & Light Company, Portland General Electric
Company, Seattle City Light, Tacoma City Light and Grays
Harbor and Snohomish County Public Utility Districts,
as the Buyers of coal for the Centralia Steam Electric
Generating Plant, dated as of January 1, 1991.
10(h)-1 2-47373 13(y) Agreement between the Company, Bonneville Power
Administration and Washington Public Power Supply
System for purchase and exchange of power from the Nuclear
Project No. 1 (Hanford), dated as of January 6, 1973.
10(h)-2 2-60728 5(m)-1 Amendment No. 1 to the Agreement between the Company
between the Company, Bonneville Power Administration and
Washington Public Power Supply System for purchase and
exchange of power from the Nuclear Project No. 1 (Hanford),
dated as of May 8, 1974.
10(h)-3 1-3701 (with 10(i)-3 Agreement between Bonneville Power Administration,
Form 10-K for the Montana Power Company, Pacific Power & Light,
1986) Portland General Electric, Puget Sound Power & Light, the
Company and the Supply System for relocation costs of
Nuclear Project No. 1 (Hanford) dated as of July 9, 1986.
10(i)-1 2-60728 5(n) Ownership Agreement of Nuclear Project No. 3, sponsored
by Washington Public Power Supply System, dated as of
September 17, 1973.
10(i)-2 1-3701 (with 1 Settlement Agreement and Covenant Not to Sue executed
Form 10-Q for by the United States Department of Energy acting
quarter ended by and through the Bonneville Power Administration
September 30, and the Company, dated as of September 17, 1985,
1985) describing the settlement of Project 3 litigation.
10(i)-3 1-3701 (with 2 Agreement to Dismiss Claims and Covenant
Form 10-Q for Not to Sue between the Washington Public
quarter ended Power Supply System and the Company, dated
September 30, as of September 17, 1985, describing the settlement
1985) of Project 3 litigation with the Supply System.
10(i)-4 1-3701 (with 3 Agreement among Puget Sound Power & Light
Form 10-Q for Company, the Company, Portland General Electric
quarter ended Company and PacifiCorp, dba Pacific Power & Light
September 30, Company, agreeing to execute contemporaneously
1985) an irrevocable offer, to and for the benefit of the Bonneville
Power Administration, dated as of September 17, 1985.
- -------------------
*Incorporated herein by reference.
**Filed herewith.
59
63
THE WASHINGTON WATER POWER COMPANY
================================================================================
EXHIBIT INDEX (continued)
Previously Filed*
----------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------
10(j)-2 2-66184 5(r) Service Agreement (Natural Gas Storage Service), dated as of
August 27, 1979, between the Company and Nation.
10(j)-3 2-60728 5(s) Service Agreement (Liquefaction-Storage Natural Gas Service),
dated as of December 7, 1977, between the Company and
Northwest Pipeline Corporation.
10(j)-4 1-3701(with 10(k)-4 Amendment dated as of January 1, 1990, to Firm
1989 Form 10-K) Transportation Agreement, dated as of June 15, 1988,
between the Company and Northwest Pipeline Corporation.
10(j)-6 1-3701 (with 10(k)-6 Firm Transportation Service Agreement, dated as of
1992 Form 10-K) April 25, 1991, between the Company and Pacific Gas
Transmission Company.
10(j)-7 1-3701 (with 10(k)-7 Service Agreement Applicable to Firm Transportation Service,
1992 Form 10-K) dated June 12, 1991, between the Company and Alberta
Natural Gas Company Ltd.
10(j)-8 1-3701 (with 10(k)-8 Natural Gas Sale and Purchase Agreement, dated
1992 Form 10-K) October 31, 1991, between the Company and
AEC Oil and Gas Company.
10(j)-9 1-3701 (with 10(k)-9 Natural Gas Purchase Contract, dated December 11, 1991
1992 Form 10-K) between the Company and Grand Valley Gas Company
and Amerada Hess Canada Ltd.
10(j)-10 1-3701 (with 10(k)-10 Natural Gas Purchase Contract, dated December 13, 1991,
1992 Form 10-K) between the Company and Grand Valley Gas Company
and PanCanadian Petroleum Limited.
10(k)-1 1-3701 (with 13(b) Letter of Intent for the Construction and Ownership
Form 8-K for of Colstrip Units No. 3 and 4, sponsored by The
August 1976) Montana Power Company, dated as of April 16, 1974.
10(k)-2 1-3701 (with 10(s)-7 Ownership and Operation Agreement for Colstrip
1981 Form 10-K) Units No. 3 and 4, sponsored by The Montana
Power Company, dated as of May 6, 1981.
10(k)-3 1-3701 (with 10(s)-2 Coal Supply Agreement for Colstrip Units No. 3 and 4
1981 Form 10-K) between The Montana Power Company, Puget Sound
Power & Light Company, Portland General Electric Company,
Pacific Power & Light Company, Western Energy
Company and the Company, dated as of July 2, 1980.
- ---------------------
* Incorporated herein by reference.
** Filed herewith.
60
64
THE WASHINGTON WATER POWER COMPANY
================================================================================
EXHIBIT INDEX (continued)
Previously Filed*
----------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------
10(k)-4 1-3701 (with 10(s)-3 Amendment No. 1 to Coal Supply Agreement for
1981 Form 10-K) Colstrip Units No. 3 and 4, dated as of July 10, 1981.
10(k)-5 1-3701 (with 10(l)-5 Amendment No. 4 to Coal Supply Agreement for Colstrip
1988 Form 10-K) Units No. 3 and 4, dated as of January 1, 1988.
10(l)-1 1-3701 (with 10(n)-2 Lease Agreement between the Company and IRE-4
1986 Form 19-K) New York, Inc., dated as of December 15, 1986,
relating to the Company's central operating facility.
10(m) 1-3701 (with 10(v) Supplemental Agreement No. 2, Skagit/Hanford Project,
1983 Form 10-K) dated as of December 27, 1983, relating to the termination
of the Skagit/Hanford Project.
10(n) 1-3701 (with 10(p)-l Agreement for Purchase and Sale of Firm Capacity and
1986 Form 10-K) Energy between Puget Sound Power & Light Company and the
Company, dated as of August 1, 1986.
10(o) 1-3701 (with 10(q)-1 Electric Service and Purchase Agreement between
1991 Form 10-K) Potlatch Corporation and the Company, dated as of
January 3, 1991.
10(p) 1-3701 (with 10(r)-1 Power Sale Agreement between the Company and the
1992 Form 10-K) Northern California Power Agency dated October 11, 1991.
10(q) 1-3701 (with 10(s)-1 Agreements for Purchase and Sale of Firm Capacity
1992 Form 10-K) between the Company and Portland General Electric
Company dated March and June 1992.
10(r)-1 1-3701 (with 10(s)-1 Employment Agreement between the Company
1994 Form 10-K) and Paul A. Redmond. (***)
10(r)-2 1-3701 (with 10(s)-2 Employment Agreement between the Company
1994 Form 10-K) and W. Lester Bryan. (***)
10(r)-3 1-3701 (with 10(s)-3 Employment Agreement between the Company
1994 Form 10-K) and Nancy Racicot. (***)
10(r)-4 1-3701 (with 10(s)-4 Employment Agreement between the Company
1994 Form 10-K) and Jon E. Eliassen. (***)
- -------------
* Incorporated herein by reference.
** Filed herewith.
*** Management contracts or compensatory plans filed as exhibits by reference
per Item 601(10)(iii) of Regulation S-K.
61
65
THE WASHINGTON WATER POWER COMPANY
================================================================================
EXHIBIT INDEX (continued)
Previously Filed*
----------------------------
With
Registration As
Exhibit Number Exhibit
- ------- ------------ -------
10(r)-5 1-3701 (with 10(s)-5 Employment Agreement between the Company
1994 Form 10-K) and Robert D. Fukai. (***)
10(r)-6 ** Executive Officers' 1995 Incentive Plan. (***)
10(r)-7 1-3701 (with 10(t)-7 Executive Deferral Plan of the Company. (***)
1992 Form 10-K)
10(r)-8 1-3701 (with 10(t)-8 The Company's Unfunded Outside Director
1992 Form 10-K) Retirement Plan. (***)
10(r)-9 1-3701 (with 10(t)-9 The Company's Unfunded Supplemental
1992 Form 10-K) Executive Retirement Plan. (***)
10(r)-10 1-3701 (with 10(t)-10 The Company's Unfunded Supplemental
1992 Form 10-K) Executive Disability Plan. (***)
10(r)-11 1-3701 (with 10(t)-11 Income Continuation Plan of the Company.(***)
1992 Form 10-K)
10(s)-1 1-3701 (with 10(t)-1 Employment Agreement between the Company, Sierra
1994 Form 10-K) Pacific Resources, Sierra Pacific Power Company,
Resources West and Paul A. Redmond. (***)
10(s)-2 1-3701 (with 10(t)-2 Employment Agreement between the Company, Sierra
1994 Form 10-K) Pacific Resources, Sierra Pacific Power Company,
Resources West and Walter M. Higgins.
12 ** Statement re computation of ratio of earnings to fixed
charges and preferred dividend requirements.
21 ** Subsidiaries of Registrant.
27 ** Financial Data Schedule.
- ----------------
* Incorporated herein by reference.
** Filed herewith.
*** Management contracts or compensatory plans filed as exhibits by reference
per Item 601(10)(iii) of Regulation S-K.
62
1
Exhibit 4(d)-2
FIRST AMENDMENT dated as of July 26, 1995 (the "Amendment"),
to the $40,000,000 Revolving Credit Agreement, dated as of
October 1, 1992 (the "Agreement"), among THE WASHINGTON WATER
POWER COMPANY, a Washington corporation (the "Borrower"), the
banks parties thereto (the "Banks") and TORONTO DOMINION (TEXAS),
INC., as agent for the Banks (in such capacity, the "Agent").
A. The Borrower has requested that the Banks amend certain provisions
of the Agreement. The Banks are willing to enter into this Amendment, subject to
the terms and conditions set forth herein.
B. Capitalized terms used and not otherwise defined herein shall have
the meanings assigned to them in the Agreement.
Accordingly, in consideration of the mutual agreements contained in
this Amendment and other good and valuable consideration, the sufficiency and
receipt of which are hereby acknowledged, the parties hereto hereby agree as
follows:
SECTION 1. Amendment of Section 1.01. The definition of "Expiration
Date" in Section 1.01 of the Agreement is hereby amended to read in its entirety
as follows:
"Expiration Date" shall mean July 24, 1996.
SECTION 2. Amendment of Section 2.05(a). Section 2.05(a) of the
Agreement is hereby amended by replacing the reference to ".20" with ".10%".
SECTION 3. Representations and Warranties. The Borrower represents and
warrants to the Agent and to each of the Banks that:
(a) This Amendment, and the Agreement as amended hereby, have
been duly authorized, executed and delivered by it and constitute its
legal, valid and binding obligations enforceable in accordance with
their terms except as such enforceability may be limited by
bankruptcy, insolvency, reorganization, moratorium or other laws
affecting the enforcement of creditors' rights generally, or by
general equity principles, including but not limited to principles
governing the availability of the remedies of specific performance and
injunctive relief.
(b) The representations and warranties set forth in Article III
of the Agreement and in the other Loan Documents before and after
giving effect to this Amendment are true and correct in all material
respects with the same effect as if made on the date hereof, except to
the extent such representations and warranties expressly relate to an
earlier date, in which case they were true and correct in all material
respects on and as of such earlier date.
(c) Before and after giving effect to this Amendment, no Default
or Event of Default has occurred and is continuing.
(d) As of the date hereof, the Borrower has performed all
obligations to be performed on its part as set forth in the Agreement
and the other Loan Documents.
SECTION 4. Conditions to Effectiveness. The amendments to the
Agreement set forth in this Amendment shall become effective when the Agent
shall have received (a) counterparts of this Amendment which, when taken
together, bear the signatures of the Borrower and each of the Banks under the
Agreement and (b) evidence satisfactory to it that the Amendment has been (or
will prior to any borrowing under the Agreement have been) duly authorized by
the Board of Directors of the Borrower.
SECTION 5. Agreement. Except as specifically amended hereby, the
Agreement shall continue in full force and effect in accordance with the
provisions thereof as in existence on the date hereof. After the date hereof,
any reference to the Agreement shall mean the Agreement as amended hereby.
2
SECTION 6. Applicable Law. THIS AMENDMENT SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW YORK.
SECTION 7. Counterparts. This Amendment may be executed in two or more
counterparts, each of which shall constitute an original, but all of which when
taken together shall constitute but one contract.
SECTION 8. Expenses. The Borrower agrees to reimburse the Agent for
its reasonable out-of-pocket expenses in connection with this Amendment,
including the reasonable fees, charges and disbursements of Cravath, Swaine &
Moore, counsel for the Agent.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to
be duly executed by their respective authorized officers as of the day and year
first written above.
THE WASHINGTON WATER POWER
COMPANY, as the Borrower,
by /s/ Ronald R. Peterson
--------------------------------
Name: Ronald R. Peterson
Title: Treasurer
TORONTO DOMINION (TEXAS),
INC., as Agent,
by /s/ Sophia D. Sgarbi
--------------------------------
Name: Sophia D. Sgarbi
Title: Vice President
THE TORONTO-DOMINION BANK,
HOUSTON AGENCY,
by /s/ Sophia D. Sgarbi
--------------------------------
Name: Sophia D. Sgarbi
Title: Manager Syndications & Credit
Administration
THE BANK OF NEW YORK,
by /s/ Daniel T. Gates
--------------------------------
Name: Daniel T. Gates
Title: Vice President
3
CIBC INC.,
by /s/ P. Saggau
--------------------------------
Name: P. Saggau
Title: Vice President
CITICORP USA,
by /s/ Mark Lyons
--------------------------------
Name: Mark Lyons
Title: Vice President
1
Exhibit 4(d)-3
SECOND AMENDMENT dated as of July 26, 1995 (the
"Amendment"), to the $50,000,000 Revolving Credit Agreement,
dated as of October 1, 1992, as amended (the "Agreement"), among
THE WASHINGTON WATER POWER COMPANY, a Washington corporation (the
"Borrower"), the banks parties thereto (the "Banks") and TORONTO
DOMINION (TEXAS), INC., as agent for the Banks (in such capacity,
the "Agent").
A. The Borrower has requested that the Banks amend certain provisions
of the Agreement. The Banks are willing to enter into this Amendment, subject to
the terms and conditions set forth herein.
B. Capitalized terms used and not otherwise defined herein shall have
the meanings assigned to them in the Agreement.
Accordingly, in consideration of the mutual agreements contained in
this Amendment and other good and valuable consideration, the sufficiency and
receipt of which are hereby acknowledged, the parties hereto hereby agree as
follows:
SECTION 1. Amendment of Section 1.01. The definition of "Expiration
Date" in Section 1.01 of the Agreement is hereby amended to read in its entirety
as follows:
"Expiration Date" shall mean July 24, 1996.
SECTION 2. Amendment of Section 2.05(a). Section 2.05(a) of the
Agreement is hereby amended by replacing the reference to ".1875" with ".10%".
SECTION 3. Representations and Warranties. The Borrower represents and
warrants to the Agent and to each of the Banks that:
(a) This Amendment, and the Agreement as amended hereby, have been
duly authorized, executed and delivered by it and constitute its legal,
valid and binding obligations enforceable in accordance with their terms
except as such enforceability may be limited by bankruptcy, insolvency,
reorganization, moratorium or other laws affecting the enforcement of
creditors, rights generally, or by general equity principles, including but
not limited to principles governing the availability of the remedies of
specific performance and injunctive relief.
(b) The representations and warranties set forth in Article III of the
Agreement and in the other Loan Documents before and after giving effect to
this Amendment are true and correct in all material respects with the same
effect as if made on the date hereof, except to the extent such
representations and warranties expressly relate to an earlier date, in
which case they were true and correct in all material respects on and as of
such earlier date.
(c) Before and after giving effect to this Amendment, no Default or
Event of Default has occurred and is continuing.
(d) As of the date hereof, the Borrower has performed all obligations
to be performed on its part as set forth in the Agreement and the other
Loan Documents.
SECTION 4. Conditions to Effectiveness. The amendments to the
Agreement set forth in this Amendment shall become effective when the Agent
shall have received (a) counterparts of this Amendment which, when taken
together, bear the signatures of the Borrower and each of the Banks under the
Agreement and (b) evidence satisfactory to it that the Amendment has been (or
will prior to any borrowing under the Agreement have been) duly authorized by
the Board of Directors of the Borrower.
SECTION 5. Agreement. Except as specifically amended hereby, the
Agreement shall continue in full force and effect in accordance with the
provisions thereof as in existence on the date hereof. After the date hereof,
any reference to the Agreement shall mean the Agreement as amended hereby.
2
SECTION 6. Applicable Law. THIS AMENDMENT SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW YORK.
SECTION 7. Counterparts. This Amendment may be executed in two or more
counterparts, each of which shall constitute an original, but all of which when
taken together shall constitute but one contract.
SECTION 8. Expenses. The Borrower agrees to reimburse the Agent for
its reasonable out-of-pocket expenses in connection with this Amendment,
including the reasonable fees, charges and disbursements of Cravath, Swaine &
Moore, counsel for the Agent.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to
be duly executed by their respective authorized officers as of the day and year
first written above.
THE WASHINGTON WATER POWER
COMPANY, as the Borrower,
by /s/ Ronald R. Peterson
--------------------------------
Name: Ronald R. Peterson
Title: Treasurer
TORONTO DOMINION (TEXAS),
INC., as Agent,
by /s/ Sophia D. Sgarbi
--------------------------------
Name: Sophia D. Sgarbi
Title: Vice President
THE TORONTO-DOMINION BANK,
HOUSTON AGENCY,
by /s/ Sophia D. Sgarbi
--------------------------------
Name: Sophia D. Sgarbi
Title: Manager Syndications & Credit
Administration
THE BANK OF NEW YORK,
by /s/ Daniel T. Gates
--------------------------------
Name: Daniel T. Gates
Title: Vice President
3
CIBC INC.,
by /s/ P. Saggau
--------------------------------
Name: P. Saggau
Title: Vice President
CITICORP USA,
by /s/ Mark Lyons
--------------------------------
Name: Mark Lyons
Title: Vice President
1
Exhibit 4(e)-2
THIRD AMENDMENT
TO
REVOLVING CREDIT AGREEMENT
THIS AGREEMENT dated as of November 21, 1994, AMENDS that certain Revolving
Credit Agreement between The Washington Water Power Company ("Borrower");
Seattle-First National Bank, West One Bank Idaho, N.A., First Interstate Bank of
Washington, N.A., First Security Bank of Idaho, N.A., U.S. Bank of Washington,
N.A. and Washington Trust Bank (the "Banks"); and Seattle-First National Bank,
as Agent for the Banks (the "Agent") dated as of December 10, 1992 (the "Credit
Agreement"), as previously amended on March 1, 1993 and January 21, 1994.
WHEREAS, pursuant to Section 2.10 of Credit Agreement, the Borrower
requested the extension of the Expiration Date; and
WHEREAS, the Banks would agree to the requested extension only if the
Borrower agreed to the following amendment;
THEREFORE, in consideration of the mutual covenants it is HEREBY AGREED as
follows:
1. The Definition of "Applicable Margin" contained in Section 1 is hereby
amended to read as follows:
"Applicable Margin" shall mean on any date, with respect to Eurodollar
Loans or ABR Loans, as the case may be, the applicable spreads set forth
below based upon the Rating Level on that date:
Eurodollar ABR
Loan Spread Loan Spread
----------- -----------
Rating Level 1 0.35% 0.0%
Rating Level 2 0.45% 0.0%
Rating Level 3 0.75% 0.5%
Each change in the Applicable Margin shall apply to all Eurodollar Loans
that are outstanding at any time during the period commencing on the
effective date of such change and ending on the date immediately preceding
the effective date of the next such change.
2. The Definition of "Commitment Fee" contained in Section 1 is hereby amended
to read as follows:
"Commitment Fee" shall mean with respect to each Bank that per annum fee
equal to the applicable rate set forth below based upon the Borrower's Rating
Level on that date:
Rating Level 1 0.15%
Rating Level 2 0.1875%
Rating Level 3 0.30%
as applied in accordance with Section 2.6(a).
3. The Expiration Date is extended to December 10, 1997, pursuant to Section
2.10 of the Credit Agreement in the same manner and to the same extent as if
there had been no amendment of the Credit Agreement.
4. Except as expressly amended by this Agreement, the Credit Agreement shall
continue in full force and effect.
2
5. This Agreement may be executed in multiple counterparts, including
signed facsimile copies followed by delivery to the Agent of the original signed
counterpart.
Dated and signed as of this 21st day of November, 1994.
Borrower:
THE WASHINGTON WATER POWER COMPANY
By /s/ Ronald R. Peterson
--------------------------------
Name: Ronald R. Peterson
Title: Treasurer
Agent:
SEATTLE-FIRST NATIONAL BANK, as agent for
the Banks
By /s/ Dora A. Brown
--------------------------------
Name: Dora A. Brown
Title: Assistant Vice President
1
Exhibit 10(r)(6)
1995 EXECUTIVE OFFICER INCENTIVE PLAN
This plan provided the opportunity in 1995 for executive officers
including Mr. Redmond to earn annual incentives in addition to their salaries.
The Compensation Committee each year establishes the target amounts as a
specified percentage of the executive officer's salary. For 1995, such
percentages ranged from 35% to 40% for executive officers and 50% for Mr.
Redmond. In the event that various goals (as more fully described under Annual
Incentives) are achieved, an executive officer may be entitled to receive the
full award and, in the event that certain performance goals have been exceeded,
an executive officer may be entitled to receive up to 150% of such targeted
percentage.
ANNUAL INCENTIVES
Each year, the Committee establishes short-term financial goals which
relate to one or more indicators of corporate financial performance.
Generally, incentive awards are paid to participating executives under the
Executive Incentive Compensation Plan only when the pre-designated financial
goals and the individual performance goals are achieved. Because the Merger
was expected to be consummated during 1995, the Committee did not establish
formal corporate financial goals for a performance period which was expected to
be less than one year, but instead based the annual incentive award upon the
overall financial performance of the Company and the individual performance of
each executive. In reviewing the Company's overall financial performance, the
Committee considered such corporate performance measures as earnings per share
growth, internal cash generation, share price appreciation, return on common
equity, book value, dividend payout ratio and cost management. The evaluation
of each executive included a determination of factors including sustained
performance of each executive's individual accountabilities, the impact of such
individual performance on the business results of the Company, effective
leadership of transition efforts, the level of the executive's responsibility,
initiative, business judgment, technical expertise, management skills, and
strategic direction. The relative importance of each of these factors was
2
discretionary on the part of the Committee, and no particular formulas or
weights were applied.
Payouts under the Executive Incentive Compensation Plan are normally
made 50% in cash and 50% in Company Common Stock, consistent with the
philosophy of the Committee that payment of a portion of the short-term
incentive opportunity in the form of Company Common Stock helps strike a
balance between the focus of executives on short-term and long-term corporate
financial results. Nevertheless, because executive officers who would have
otherwise received stock as compensation within six months prior to the
effective date of the Merger could have been subject to adverse consequences
under the federal securities laws, stock could not be granted for 1995
performance, and all incentive awards for 1995 were paid in cash.
LONG-TERM INCENTIVES
No long-term goals were established for 1995 because it was assumed the
Merger would close before year-end.
-2-
1
EXHIBIT 12
THE WASHINGTON WATER POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges and Preferred Dividend
Requirements(1)
Consolidated
(Thousand of Dollars)
YEARS ENDED DECEMBER 31
-----------------------------------------------
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Fixed charges, as defined:
Interest on long-term debt $ 55,580 $ 49,566 $ 47,129 $ 51,727 $ 52,801
Amortization of debt expenses
and premium -- net 3,441 3,511 3,004 1,814 1,751
Interest portion of rentals 3,962 1,282 924 1,105 1,018
-------- -------- -------- -------- --------
Total fixed charges $ 62,983 $ 54,359 $ 51,057 $ 54,646 $ 55,570
======== ======== ======== ======== ========
Earnings, as defined:
Net income from continuing ops. $ 87,121 $ 77,197 $ 82,776 $ 72,267 $ 70,631
Add (deduct);
Income tax expense 52,416 44,696 42,503 41,330 38,086
Total fixed charges above 62,983 54,359 51,057 54,646 55,570
-------- -------- -------- -------- --------
Total earnings $202,520 $176,252 $176,336 $168,243 $164,287
======== ======== ======== ======== ========
Ratio of earnings to fixed charges 3.22 3.24 3.45 3.08 2.96
Fixed charges and preferred
dividend requirements:
Fixed charges above $ 62,983 $ 54,359 $ 51,057 $ 54,646 $ 55,570
Preferred dividend requirements(2) 14,612 13,668 12,615 10,716 14,302
-------- -------- -------- -------- --------
Total $ 77,595 $ 68,027 $ 63,672 $ 65,362 $ 69,872
======== ======== ======== ======== ========
Ratio of earnings to fixed charges
and preferred dividend requirements 2.61 2.59 2.77 2.57 2.35
(1) Calculations have been restated to reflect the results from continuing
operations (i.e. excluding discontinued coal mining operations).
(2) Preferred dividend requirements have been grossed up to their pre-tax
level.
1
Exhibit 21
THE WASHINGTON WATER POWER COMPANY
SUBSIDIARIES OF REGISTRANT
Subsidiary State of Incorporation
- --------------------------------------------- ----------------------
Pentzer Corporation Washington
Washington Irrigation and Development Company Washington
WP Finance Company Washington
Altus Laboratories Washington
Altus Energy Solutions Washington
UT
1,000
12-MOS
DEC-31-1995
DEC-31-1995
PER-BOOK
1,357,418
227,457
183,972
330,055
0
2,098,902
582,946
9,148
125,031
717,125
85,000
50,000
651,775
29,500
18,484
0
41,669
0
3,528
5
501,816
2,098,902
755,009
52,416
565,169
565,169
189,840
8,719
198,559
59,022
87,121
9,123
77,998
68,392
31,236
132,232
1.41
1.41
LONG-TERM DEBT-NET DOES NOT MATCH THE AMOUNT REPORTED ON THE COMPANY'S
CONSOLIDATED STATEMENT OF CAPITALIZATION AS LONG-TERM DEBT DUE TO THE OTHER
CATEGORIES REQUIRED BY THIS SCHEDULE.
OTHER ITEMS CAPITAL AND LIABILITIES INCLUDES THE CURRENT LIABILITIES,
DEFFERED CREDITS AND MINORITY INTEREST, LESS CERTAIN AMOUNTS INCLUDED UNDER
LONG-TERM DEBT-CURRENT PORTION AND LEASES-CURRENT, FROM THE COMPANY'S
CONSOLIDATED BALANCE SHEET.
THE COMPANY DOES NOT INCLUDE INCOME TAX EXPENSE AS AN OPERATING EXPENSE
ITEM. IT IS INCLUDED ON THE COMPANY'S STATEMENTS AS A BELOW-THE-LINE-ITEM.
INCOME BEFORE INTEREST EXPENSE IS NOT A SPECIFIC LINE ITEM ON THE COMPANY'S
INCOME STATEMENTS. THE COMPANY COMBINES TOTAL INTEREST EXPENSE AND OTHER INCOME
TO CALCULATE INCOME BEFORE INCOME TAXES.
